[Federal Register Volume 68, Number 34 (Thursday, February 20, 2003)]
[Rules and Regulations]
[Pages 8402-8435]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-3425]
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Part III
Department of the Interior
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Minerals Management Service
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30 CFR Part 250
Oil and Gas and Sulphur Operations in the Outer Continental Shelf--Oil
and Gas Drilling Operations; Final Rule
Federal Register / Vol. 68, No. 34 / Thursday, February 20, 2003 /
Rules and Regulations
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DEPARTMENT OF THE INTERIOR
Minerals Management Service
30 CFR Part 250
RIN 1010-AC43
Oil and Gas and Sulphur Operations in the Outer Continental
Shelf--Oil and Gas Drilling Operations
AGENCY: Minerals Management Service (MMS), Interior.
ACTION: Final rule.
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SUMMARY: This final rule restructures the requirements for oil and gas
drilling operations on the Outer Continental Shelf (OCS), adds some new
requirements, and converts the regulations into plain language. The
restructuring of the rule follows the logical sequence of obtaining
approval to drill a well and conducting drilling operations. The final
rule also removes overly prescriptive requirements and updates
requirements to reflect changes in drilling technology. Restructuring
the drilling requirements makes the regulations easier to read,
understand, and follow. The technical changes will help ensure that
lessees conduct operations in a safe manner.
EFFECTIVE DATE: The rule is effective March 24, 2003. The incorporation
by reference of publications listed in the regulation is approved by
the Director of the Federal Register as of March 24, 2003.
FOR FURTHER INFORMATION CONTACT: William Hauser, Engineering and
Operations Division, at (703) 787-1613.
SUPPLEMENTARY INFORMATION: On June 21, 2000, we published a Notice of
Proposed Rulemaking (65 FR 38453), titled ``Oil and Gas and Sulphur
Operations in the Outer Continental Shelf--Oil and Gas Drilling
Operations'' to revise the subpart D regulations of part 250, with
exception of the regulations on Hydrogen Sulfide under 30 CFR 250.417.
The proposed rule had a 90-day comment period that we extended to 120
days on July 27, 2000 (65 FR 46126). The extended comment period closed
on October 19, 2000.
Differences Between Proposed and Final Rules Not Directly Related to
Comments
In addition to changes we made to the final rule in response to
public comments, we reworded several sections to further clarify the
requirements. We also changed several section titles to better reflect
the intent of the sections. The following are the changes by section:
[sbull] Section 250.403--We divided the requirements contained in
the table in this section into three new sections. We believe this
change provides a better understanding of the requirements. The new
sections are:
250.404 What are the requirements for the crown block?
250.405 What are the safety requirements for diesel engines on a
drilling rig?
250.406 What additional safety measures must I take when I conduct
drilling operations on a platform that has producing wells or has other
hydrocarbon flow?
[sbull] New Sec. 250.405--We added engines on escape capsules to
the list of diesel engines that you do not have to equip with an air
intake device. We believe that this device should not be required on an
escape capsule. We also revised paragraph (b) by adding the term
``remote'' to manual air intake shutdown device so that the requirement
means the same as the previous requirement. Paragraph (b) now reads as
follows: ``For a diesel engine that is continuously manned, you may
equip the engine with either an automatic or remote manual air intake
shutdown device;''.
[sbull] New Sec. 250.406(b)--This paragraph applies to shutting in
producing wells during the movement of a drilling rig on and off a
location. We clarified the requirements of this section in response to
comments from the Offshore Operators Committee (OOC) (see discussion in
OOC comments section). We want to further clarify in the preamble of
this rule that the same requirements to shut in producing wells would
apply when a lessee moves in a drilling rig or coiled tubing unit to
complete or workover a well. We plan to clearly state these
requirements for completion and workover activities in revisions of
subparts E and F that we anticipate proposing.
[sbull] Sections 250.408 and 250.409--We added two new sections to
address the use of alternative procedures or equipment during drilling
operations and obtaining departures from the drilling regulations. We
made this revision to clearly state the procedures for using
alternative procedures or equipment and for obtaining departures from
the drilling regulations. We also removed phrases similar to ``or as
otherwise approved by the District Supervisor'' throughout the rule
because you may request a departure or the use of alternative
procedures or equipment with respect to any of the drilling
requirements prescribed in the rule, provided the rationale is
appropriate.
[sbull] Section 250.414--We added an introductory sentence to this
section which states that the drilling prognosis must include a brief
description of the procedures that you will follow in drilling the
well. That description includes the nine items listed (a) through (i)
in this section and any other events or procedures that are out of the
ordinary for drilling activities. We also moved the paragraph on
listing and describing departures or requests to use alternative
procedures and equipment to this section.
[sbull] Section 250.421(d)--We revised this paragraph to read as
follows: ``As a minimum, you must cement the annular space 500 feet
above the casing shoe and 500 feet above each zone to be isolated.'' We
inserted the phrase ``500 feet above'' before ``each zone'' to ensure
that there was no confusion about cementing requirements for the
intermediate casing. This clarification is consistent with the current
regulations.
[sbull] Section 250.424--We converted the requirements for pressure
testing casing into a table. This will make the requirements easier to
understand.
[sbull] Section 250.427--We clarified the requirement for when you
must conduct a pressure integrity test after drilling new hole below
the casing shoe. The original requirement stated a maximum amount that
you could drill before conducting the test (50 feet). The revised
requirement has both a minimum (10 feet) and a maximum (50 feet) amount
that you could drill before conducting the test. This will remove any
confusion about how much new formation you must drill before conducting
the test.
[sbull] Section 250.465(a)(3)--We revised this paragraph to require
the submittal of a plat certified by a registered land surveyor when
you determine the well's final surface location, water depth, and the
rotary kelly bushing elevation. This requirement is consistent with the
current regulations. The certified plat serves a useful purpose because
it provides certainty to the well's location. In some instances,
submittals of non-certified plats or reliance upon the planned location
plat provide only a rough idea of where the well may be located.
Changes to Drilling and Well Forms Not Related to Comments
Through a separate process, MMS revised the associated 30 CFR 250,
subpart D, drilling and well forms MMS-123, MMS-123S, MMS-124, MMS-125,
and MMS-133. We are conducting the form revisions in compliance with
the requirements of the Paperwork Reduction Act of 1995 (PRA), and as
part of our efforts to implement the Government Paperwork
[[Page 8403]]
Elimination Act and streamline data collection. The revised forms were
published for comment in the Federal Register on May 1, 2002 (67 FR
21718). In addition to revising some of the data elements on each form,
we changed the titles of forms MMS-124 (Sundry Notices and Reports on
Wells changed to Application for Permit to Modify), MMS-125 (Well
Summary Report changed to End of Operations Report), and MMS-133
(Weekly Activity Report changed to Well Activity Report). In accordance
with the PRA, we submitted the revised forms to the Office of
Management and Budget (OMB) for approval. The OMB approved the use of
the new forms in October 2002 and these final regulations incorporate
the changes to the forms.
Comments on the Rule
We received 11 sets of comments on the proposed rule and other
considerations for drilling regulations. The comments came from four
oil and gas lessees/operators (Chevron USA Production Company, Shell
Exploration & Production Company, Torch Operating Company, and Mariner
Energy), two drilling contractors (Noble Drilling Services and Rowan
Companies), three trade organizations (American Petroleum Institute
(API), OOC, and International Association of Drilling Contractors
(IADC), one consultant (West, Inc.), and one private citizen (James E.
May). You may view these comments and the Notice of Proposed Rulemaking
(NPR) on the MMS Web site at address: http://www.mms.gov/federalregister/PublicComments/rulecomm.htm. The OOC and IADC provided
the most comprehensive sets of comments on the proposed rule. Three of
the operators and both drilling contractors fully supported the
comments of their respective trade organizations and provided
additional comments. The API noted that it worked with OOC in preparing
detailed comments on the rule and fully supports the comments submitted
by OOC. The OOC presented its comments on specific sections of the rule
in a table that identified the section, suggested changes, and provided
rationale for those changes. We found this to be an informative format
for reviewing comments and have used that format to respond to OOC's
comments.
We organized our responses to comments on the NPR into three
sections. These sections address the following topics:
I. General comments and comments on other considerations for
drilling regulations (i.e., need for regulations on the use of coiled
tubing, mandatory use of automated pipe handling systems);
II. Comments on specific sections that OOC did not address in its
comments; and
III. OOC's comments on specific sections (table format).
I. General Comments and Responses
[sbull] Comment: The use of Lessees/Operators/Contractors relates
better to these regulations than the use of ``I'' and ``you.''
Response: We disagree. The use of ``I'' and'' ``you'' in the
regulations essentially replaces the terms ``lessees, operators, and
contractors.'' It is much easier to say ``you must'' versus the
``lessee/operator/contractor must.''
[sbull] Comments on Incorporating API Recommended Practice (RP) 53,
Recommended Practice for Blowout Prevention Equipment Systems for
Drilling Wells (API RP 53) into the regulations: One commenter stated
that the incorporation of specific sections of API RP 53 is appropriate
because incorporation of the entire document would lack the specificity
needed for the regulations. Another commenter recommended that the
entire contents of API RP 53 should be incorporated by reference to
provide overall guidelines for blowout preventer (BOP) systems.
Response: MMS has incorporated specific sections of API RP 53 into
the regulations as proposed. The primary reason for selecting specific
sections was to provide needed specificity to the existing
requirements. However, API RP 53 provides excellent guidelines for
operating and maintaining BOP systems, and MMS will consider
incorporating the entire document in a future revision of the drilling
regulations.
MMS will also consider the incorporation of other API drilling
documents. MMS recently contracted with West, Inc. to review and
compare three API Recommended Practices to MMS regulations and IADC's
Deepwater Guidelines. The three Recommended Practices are:
1. 16E--Design of Control Systems for Drilling Well Control
Equipment;
2. 64--Diverter System Equipment and Operations; and
3. 16Q--Design, Selection, Operation, and Maintenance of Marine
Drilling Riser Systems.
West, Inc.'s complete report is available on the MMS Web site at
ftp://www.mms.gov/TARProjects/380/380AA.pdf.
[sbull] Comments on Automated Pipe Handling Systems: This topic
generated many comments, most of which disagreed with requiring
automated pipe handling systems. Comments against requiring these
systems included the following:
--Little data exist to support the theory that automated pipe handling
systems measurably improve personnel safety;
--Automated pipe handling systems create new safety hazards (i.e., new
pipe racking systems have introduced additional tripping hazards to rig
floor personnel which have resulted in lost time incidents);
--Costs (including capital and out-of-service time) to retrofit the
drilling units would not be justified considering the perceived safety
benefits;
--Some drilling units could not be retrofitted due to space limitations
and/or due to the added weight of the automated pipe handling
equipment; and
--Reliability is an issue with some automated systems
Other comments questioned if automated systems meant totally
automated pipe handling systems or just a subset of automated rig floor
equipment such as iron roughnecks, spinners, and power slips.
Commenters also asked if operations would have to be suspended if the
automated systems were not available due to downtime. While the vast
majority of the comments were against requiring automated systems, one
comment said that MMS should require some automated rig floor
equipment, but those requirements should be flexible and a practical
application of existing technology.
Response: MMS appreciates the comments industry has provided on
this topic, and we now have a better understanding of how a requirement
for an automated pipe handling system could impact the drilling
industry and drilling operations. One of the purposes for raising this
issue in the preamble of the proposed rule was to elicit this
information. This final rule does not include any requirements for
automated pipe handling systems or automated rig floor equipment. Nor
is MMS proceeding with any proposed regulations on these systems at
this time.
[sbull] Comments on Best Cementing Practices: Most comments were
along the lines that best cementing practices should be used where
possible, but that specific practices should not be mandated by
specific requirements. OOC stated that the complexity of cementing
operations and a variety of cements are not good candidates for
prescriptive requirements. One suggested approach was to supplement
current cement compressive strength and height requirements with
regulatory
[[Page 8404]]
guidelines that would allow the needed flexibility to determine which
practices are applicable to the particular down-hole environment.
Several commenters noted that they are participating in an API/
International Standards Organization (ISO) Cementing Committee to
discuss best cementing practices with MMS and develop appropriate
guidance for best cementing practices.
Response: MMS will continue with the cementing requirements as
proposed in this rule. These requirements are similar to the
requirements that were in the previous regulations. As noted in the
above comment, MMS is participating in the API/ISO Cementing Committee
and will work with the committee to develop appropriate guidelines for
cementing practices. We may take further regulatory actions after the
committee completes its work.
[sbull] Comment: One commenter said that the proposed regulations
do not protect the environment enough, and that MMS is aware of a
substantial number of OCS wells that are leaking oil to the surface and
between formations. The commenter asserted that the proposed rule
aggravates this problem by using the term ``cementing.'' The commenter
asked why MMS allows oil companies to use cement and not other
sealants.
Response: MMS believes that the proposed regulations for cementing
wells provide adequate protection to the environment. MMS also believes
that there are opportunities to improve cements and cementing practices
so, over the years, MMS has participated in a number of research
projects that examined ways to improve cementing in oil and gas wells.
We continue to participate in cementing research efforts and other
efforts, such as the API/ISO Cementing Committee, to ensure that
cementing technology continues to advance. MMS requires industry to use
cement to seal formations and plug wells because it works; however, we
will allow industry to use other sealants if they provide equal or
better performance than cement. In the past, these generic requests to
expand the rules to allow the use of other ``sealants'' have sometimes
actually been attempts to get approval to use clays, gels, and other
low compressive strength, non-hardening compounds.
MMS knows of only a few abandoned wells that have leaked after
permanent abandonment. When we become aware of an abandoned well that
is leaking, we require the operator of record to take immediate action
to remedy the situation. Also, to further our awareness of potential
leaking abandoned wells, MMS has recently sponsored research to
identify leaking abandoned wells by using remote sensing.
[sbull] Comment on regulating coiled tubing drilling: The OOC
commented that MMS was taking the correct approach by not proposing
specific regulations for coiled tubing drilling. OOC agreed that a
better understanding of these operations and the amount of activity
that is likely to take place on the OCS was necessary before drafting
regulations. OOC stated that the existing/proposed provisions in
subpart D, coupled with the District Supervisors' authority to approve
alternative techniques and procedures, adequately addresses the
regulatory mandates. OOC also supported the use of API RP 5C7 for
Coiled Tubing Operations in Oil and Gas Well Services (API RP 5C7) as a
guideline when preparing the appropriate regulations.
Response: MMS will continue to monitor the use of coil tubing on
the OCS and will propose additional regulations as needed.
II. Comments on Specific Sections That the OOC Did Not Address in Its
Comments
[sbull] Comment on Sec. 250.404 What mobile drilling unit
movements must I report? This requirement should be waived after
commencement of the first well on a platform.
Response: We have revised this section to clearly state what rig
movements the lessee must report to MMS. This includes the movement of
both mobile offshore drilling units (MODU) and platform rigs. We need
this information to ensure that our inspectors have the correct
information in hand when they arrive at a platform rig to perform an
inspection. MMS also needs to know the movement of drilling rigs,
coiled tubing units, and snubbing units on and off locations for
completion and workover activities, so we will clarify these
requirements in revisions of 30 CFR 250, subparts E and F that we
anticipate proposing.
[sbull] Comment on Sec. 250.404 What mobile drilling unit
movements must I report? The proposed rule duplicates U.S. Coast Guard
(USCG) requirements to report MODU movements under 33 CFR parts 67 and
72. While the proposed rule affects the lessee, the MODU owner is
reporting the required information to the USCG. MMS and USCG should
share this information so that you can eliminate a reporting
requirement.
Response: MMS needs MODU movement information 24 hours in advance
of movement to plan our rig inspections. USCG's timing requirements for
rig movement notice do not meet our rig inspection planning needs.
Based on similar comments during the process to develop the new MMS
form to report rig movements, we incorporated ``optional'' information
needed by the USCG so that the form could be used for reporting to
either agency.
[sbull] Comment on Sec. 250.412 What requirements must my plat
meet? The lessee or operator should be allowed to decide how to report
well location.
Response: MMS must have the coordinates reported in a consistent
manner to ensure that the exact well locations are known.
[sbull] Comment on Sec. 250.417 What information must I provide if
I intend to use a mobile drilling unit to drill a proposed well?
Paragraph (c) may require a third-party review of a MODU's design by a
Certified Verification Agent. This review may involve the MODU's
structural components or integrity which would be in direct conflict
with the December 1998 Memorandum of Understanding (MOU) between MMS
and USCG. Under that MOU, the USCG has full responsibility for the
structural integrity of MODUs.
Response: This is not a new requirement (see current regulation at
Sec. 250.401(a)(3)). The purpose of this requirement is to address the
possible unique drilling unit that a lessee may propose to use in a
frontier area. Our intent is to ensure that proper design reviews are
conducted before the unit's use at a proposed frontier location. When
this situation occurs, MMS will confer with the USCG concerning the
drilling unit design and its use at the specified location. If the USCG
design review meets our concerns, then MMS will not require additional
design reviews. If additional reviews are needed, the District
Supervisor will use this requirement to address necessary information.
We have revised this paragraph to clarify that this requirement applies
only to frontier areas where the drilling unit design is unique or the
unit has not been proven for use in the proposed environment. MMS will
follow the 1998 MMS/USCG MOU to the extent possible to minimize
duplicating design requirements of both agencies.
[sbull] Comments on Sec. 250.417(h) and 250.418(a). The IADC and
two drilling contractors commented that these paragraphs indicate that
MMS is maintaining files of rig-specific information. While such action
by MMS is clearly in a drilling contractor's interest, they could not
find the authority for MMS to maintain files on individual drilling
rigs or to transfer this
[[Page 8405]]
information between the files of lessees/operators.
The commenters were frustrated that MMS interprets its legislative
authority as precluding direct contact between the agency and rig
owners. They are convinced that direct communication between MMS and
MODU owners/operators is permissible and advisable. They recommended
that MMS should review and approve the use of MODUs and platform rigs
on a regional basis. This would eliminate what appears to be a
repetitive and non-productive review of identical drilling rig
specifications by its District Offices.
Response: The lessee/operator must submit a detailed description of
the drilling unit including specifications for all its components,
regardless of whether it is a MODU, with the Application for Permit to
Drill (APD) a new well. MMS may communicate with the contractor;
however, it is the responsibility of the lessee/operator to submit the
required information to MMS. Drilling unit documents are part of the
APD and are maintained in well data files by MMS.
MMS does maintain limited files (work history, where and when
built, depth capability and water depth, safe welding area approval,
USCG certificate, etc.) on drilling rigs in the Gulf of Mexico (GOM).
This information is useful as a cross reference of submitted
information and when the lessee/operator does not include rig-specific
information with the APD or sundry notice. Such information is used
only within MMS (although much is readily available on the company Web
sites) and is not transferred between lessees/operators. MMS only
requires submission of this basic rig information and job-specific
information such as BOP sketch, diverter sketch, and similar related
information. This job-specific information can change due to rental
BOPs and diverters or procedural changes.
MMS drilling and workover engineers, as well as inspectors,
regularly talk with rig owners, superintendents, pushers, drillers, and
operator personnel about rig conditions, pollution, new equipment,
training, accidents, etc. Only those items specific to a location,
items that must be renewed regularly (certificates), and training are
reviewed for each APD or sundry notice, and even some of these are only
checked by the inspector once work has started. It is up to the lessee/
operator via their contracts to require that rig owners conform to MMS
regulations.
[sbull] Comment on Sec. 250.422(b) When may I resume drilling
after cementing? A commenter said that the waiting time before removing
the diverter is not necessary.
Response: MMS disagrees. Determining the time when it is safe to
remove the diverter is just as important as determining the time for
the BOP because several incidents have involved early removal of the
diverter.
[sbull] Comment on Sec. 250.423(f) How must I remedy cementing and
casing problems and irregularities? A commenter suggested that field-
specific rules rather than general rules should apply to the
requirement that you must have at least two cemented casing strings to
produce a well.
Response: Field rules could apply if they are established in
accordance with Sec. 250.463.
[sbull] Comment on Sec. 250.424(b) What are the requirements for
pressure testing casing? The requirement should allow an exception for
horizontal cementing applications.
Response: To obtain an exception for pressure testing casing, you
may request approval from the District Supervisor to use alternative
procedures (Sec. 250.408) or obtain a departure (Sec. 250.409). The
District Supervisor will evaluate these requests on a case-by-case
basis. Therefore, we did not include an exception for horizontal
cementing applications in the requirements.
[sbull] Comment on Sec. 250.430 When must I install a diverter
system? MMS shouldn't require installation of a diverter when returns
are taken at the ocean floor (i.e., no casing/riser on which to install
a diverter).
Response: The regulations require the installation of a diverter
system before you drill a conductor or surface hole. If you want to
drill a conductor or surface hole without a diverter, you must include
this procedure in your APD and obtain approval from the District
Supervisor.
[sbull] Comment on Sec. 250.431 What are the diverter design and
installation requirements? MMS should consider removing statements from
the regulations that are not auditable, such as minimizing the number
of turns or maximizing the radius of curvature of turns for diverter
lines for bottom-founded drilling units. MMS could reference industry
standards such as API RP 53 to better define what is required.
Response: MMS will continue with the current performance standards
of minimizing the number of turns and maximizing the radius of
curvature of turns for diverter lines. We used these standards in past
regulations because it is difficult to prescribe measures that will
work for each drilling unit. However, in future rulemakings, we will
consider incorporating additional standards to address some of the
requirements that are difficult to audit.
[sbull] Comment on Sec. 250.433 How must I test the diverter
system after installation? MMS should allow for testing diverters on a
14-day frequency.
Response: MMS conducted several studies on BOP performance before
we revised the regulations to allow for testing BOPs on a 14-day
frequency. We made sure that extended testing frequency would not
compromise safety during drilling operations. MMS will not consider
revising the testing frequency for diverters until research shows that
an extended testing frequency will not compromise safety.
Comments on Sec. 250.441 What are the requirements for a surface
BOP stack?
This section proposed that each surface BOP stack must have at
least one preventer equipped with blind-shear rams within 1 year after
the effective date of this final rule. This proposed requirement
prompted many comments. Four commenters opposed the proposed
requirement and provided reasons for their opposition. IADC provided
the most comprehensive comments against this proposed requirement. A
fifth commenter stated that it also opposed the proposed requirement
and said it supported IADC's comments. Three other commenters stated
that they supported IADC's and OOC's comments but they did not
specifically mention the proposed requirement for blind-shear rams. Two
other commenters also provided comments on this proposed requirement
and those comments are included below.
A summary of all the comments on the proposed requirements for
blind-shear rams follows:
--IADC plotted the incidents over the 20-year period, and its graph
showed that the incident rate where blind-shear rams might have
prevented a serious blowout is approaching zero. IADC believes that
this trend is sufficient to negate the need for MMS to mandate the
installation of the blind-shear rams. Possible activities that lead to
this declining trend include:
[sbull] Greater attention being paid to safety management as a
result of Safety and Environmental Management Programs and other
initiatives;
[sbull] Continuous improvement in well control methods and
equipment; and
[sbull] Greater attention to the quality of well control training
--IADC also stated the following:
[[Page 8406]]
[sbull] Successful operation of blind-shear rams (intentional or
not) permanently forecloses other well control options;
[sbull] MMS did not consider the consequences of inadvertent
operation or malfunction of the rams;
[sbull] MMS underestimated the number of surface BOP stacks that
would need blind-shear rams by 50 percent, thus underestimating the
costs by 50 percent; and
[sbull] If the final rule requires the blind-shear rams, then
industry will need an additional 2 years to comply with the
requirement.
--Operating limits of blind-shear rams are frequently unclear for some
drilling operations due to pipe grades, mud weights, and wellbore
pressures, and that consideration should be given to ensure that these
limits are clear
Response: MMS continues to believe that having blind-shear rams in
a surface BOP stack is an important safety measure. Blind-shear rams
offer an additional opportunity to control the well in a difficult
situation. We believe that these rams provide the last line of defense
against a blowout when drill pipe or tubing is hung in the BOP stack
and there are difficulties in installing or closing the drill string
safety valve, inside BOP, or tubing safety valve. Successful operation
of the blind-shear rams may prevent damage to the drilling rig,
platform, or other facilities, and prevent injuries or the loss of
life.
The IADC and industry provided a number of comments on why MMS
should not require blind-shear rams in surface BOP stacks. Their most
compelling reason against requiring blind-shear rams is industry's
recent performance concerning incidents where blind-shear rams might
have prevented or minimized a blowout. Those comments are correct in
that industry's recent performance is good, especially when compared to
the relatively high number of incidents that occurred in the early
1980's. However, there have been three serious incidents where blind-
shear rams may have prevented a blowout since 1996 (two incidents
occurred in 2001). A brief description of each event follows:
Incident 1--occurred on Platform A, Eugene Island Block 380, on
January 24, 1996. During completion operations, the well began to flow
while the tubing was extended above the BOP stack. The crew tried to
stab the top drive into the top of the tubing but the flow had
increased and they were unable to make the connection. The driller
closed the blind rams to reduce the flow but that did not help. Gas
began to flow out of the top of the tubing, so the drilling crew closed
the pipe rams and annular preventer and evacuated the rig floor. During
the evacuation of the rig and platform, the well caught fire. The fire
destroyed the rig substructure and derrick and severely damaged other
parts of the rig. Fortunately there were no injuries or pollution.
After investigating the accident, MMS' investigation team recommended
that blind-shear rams should be required in surface BOP stacks. The
investigation report can be found on our Web site at: http://www.gomr.mms.gov/homepg/offshore/safety/acc_repo/98-0012.pdf.
Incident 2--occurred on Platform A Eugene Island Block 277, on July
6, 2001. While killing a kick that occurred during workover operations,
the pressure safety valve on the mud pump ruptured. The well then
flowed uncontrolled through the drill pipe and the ruptured pressure
safety valve. The area around the rig equipment and drill floor became
inundated with a hazardous accumulation of gas and formation sand which
forced all personnel to evacuate to a standby boat. Fortunately there
were no injuries and only major damages to the rig. The investigation
report can be found on our Web site at: http://www.gomr.mms.gov/homepg/offshore/safety/acc_repo/2002-040.pdf.
Incident 3--occurred on a jack-up drilling rig drilling in Brazos
Block 417 on July 13, 2001. During drilling operations, the well began
to flow while the crew was making up the next joint of drill pipe in
the mouse hold. The rig floor safety valve was stabbed but would not
close with two men applying torque to the handle. Both men were burned
on their arms and back by the hot mud. Because of the high temperature
of the mud, the men had to put on slicker suits and were sprayed with
water to continue working on the rig floor. A third man assisted in the
attempt to close the valve and sufficient torque was applied to the
closing handle to shear it off at the key opening of the valve. Mud
continued flowing out of the drill pipe until it was shooting over the
the top of the derrick. Gas began to flow with the mud from the drill
pipe and it became unsafe to work on the rig floor. The crew was
ordered to abandon the rig. After the rig was abandoned, it was
discovered that the night supervisor was missing. The Coast Guard
searched for two days but the night supervisor was never found. The BOP
stack, casing and drill pipe were damaged by high pressure gas and sand
that flowed from the well. The rig was also damaged by the gas and sand
flow. The investigation report can be found on our Web site at: http://www.gomr.mms.gov/homepg/offshore/safety/acc_repo/2002-062.pdf.
In these incidents, the drilling crews had run out of options to
control the well and were forced to abandon the rig. We believe that
the injuries, the fatality, and rig damages could have been avoided if
blind-shear rams were in the BOP stack and were closed prior to
evacuating the rig. Similar incidents have occurred during drilling,
workover, and completion operations in the past, and blind-shear rams
stopped the blowout. Similar incidents are very likely to occur in the
future.
In the preamble of the proposed rule, MMS stated that it had
reviewed the blowouts that have occurred since 1977 and found at least
12 incidents where blind-shear rams had helped or could have helped
control the situation. Upon closer review of our records, we have
identified 24 incidents where blind-shear rams either helped control a
blowout or may have helped prevent a blowout (these records include
MMS's database, memoranda, accident reports, investigations, operator
letters, and operator investigations). The table below gives the date,
location, and a brief description of each of those incidents. There
were 10 fatalities, 23 injuries, 3 rigs destroyed, and 9 rigs damaged
during those incidents. Furthermore, six of the investigation reports
recommended that blind-shear rams be installed in surface BOP stacks.
Considering that the installation of blind-shear rams provides an
additional means of controlling a blowout and can help prevent future
injuries, fatalities, and protect property and the environment, MMS
will require the installation of blind-shear rams in surface BOP
stacks.
----------------------------------------------------------------------------------------------------------------
Date Block/lease Description of incident
----------------------------------------------------------------------------------------------------------------
6/23/77..................... Eugene Island 307, G 2110........................ Blowout while running dual
completion string. Tubing was
84 feet above the drill floor
when well began blowing
through the tubing. The tubing
safety valve could not be
installed so blind rams were
closed but only crimped the
tubing. Crew evacuated the rig
safely. The blowout was
controlled later that day. The
Investigation Report
recommended that the U.S.
Geological Survey require
shear rams on all BOP stacks.
[[Page 8407]]
7/20/77..................... West Cameron 110, OCS 081........................ Blowout occurred during
workover operations. Well
began to flow while pulling
out of the hole. Drill string
safety valve was installed but
could not be closed. Blind
rams were closed to restrict
the flow but had no effect.
There were no injuries. Well
Control Team secured well 4
days later.
11/26/77.................... Eugene Is. 307 G, 2110........................... Well blew out while running
into the hole during
completion operations. All of
the BOP's were closed but the
well continued to flow. The
flow was too great to stab the
drill string safety valve.
After 6 hours of attempting to
diminish the flow through the
drill pipe, the crew was able
to install and close the drill
string safety valve.
8/4/78...................... Grand Isle 41, G 0129............................ Blowout occurred during
completion operations. Drill
string safety valve could not
be closed after well began to
flow. After 15 minutes, the
driller regained control of
the well by closing blind-
shear rams. There were no
injuries.
3/5/79...................... S. Marsh Island 281, G 2600...................... While attempting to correct
lost returns and stuck pipe
problems, the well began to
flow. The crew could not close
the drill string safety valve
when the well kicked the final
time. There were eight
fatalities and considerable
damage to rig. The USCG
Investigation Report (Oil &
Gas Journal, p. 148, Nov. 17,
1980) concluded that shear
rams could prevent similar
casualties in the future.
8/24/80..................... Vermilion 348, G 2271............................ The well kicked while making up
gravel pack assembly. The
blind and pipe rams were
closed on 4\1/2\'' pipe
portion of gravel pack
assembly but did not seal the
well. The drilling rig and
portion of platform were
destroyed. There were four
minor injuries in the crew
evacuation. The well bridged
37 days later.
1/12/81..................... High Island 38, G 0477........................... Blowout occurred while
circulating out a kick. The
well blew out through the neck
on the swivel. The lower kelly
cock was left 12 feet above
the drill floor and was not
closed. The blowout lasted
approximately 12 hours,
catching fire towards the end
of the incident. Three people
suffered overexposure after
the evacuation and one later
died.
7/26/81..................... South Pelto 18, G3589............................ Blowout during completion
operations. While circulating
mud, the well kicked. Crew
closed upper kelly cock but it
leaked. Operator closed blind-
shear rams and evacuated
platform. Gas leaked through
the blind-shear rams but the
rig never caught fire. Well
was controlled 4 days later.
One person suffered a broken
leg and bruises during the
evacuation.
10/5/81..................... Eugene Island 273, G 0987........................ Blowout occurred when the
tubing parted during
completion operations. The
well was controlled after 38.5
hours by installing and
closing blind-shear rams. The
Investigation Report
recommended that BOP stacks
have blind-shear rams for
completion operations. There
were no injuries during the
evacuation.
11/28/81.................... Viosca Knoll 900, G 2445......................... Blowout occurred during
workover operations. The well
kicked while pulling out of
the hole. The BOPs were
closed, but the flow through
the drill string was too great
to stab the drill string
safety valve. The blowout
lasted 24 hours. There was
some pollution but no injuries
and minimal damages.
4/19/82..................... Galveston 391, G 3740............................ Blowout occurred while
completing the well. A drill
string safety valve could not
be installed because the drill
pipe was above the monkey
board. Well bridged over in 3
hours. There were no injuries
and only minimal damage to the
platform and rig.
5/15/82..................... S. Marsh Island 155, G 4110...................... While circulating a kick, an
explosion and fire occurred
under the rig floor and at the
shale shaker. Blind-shear rams
were activated and the well
was shut in. Three people
suffered minor injuries during
the evacuation.
7/14/82..................... West Cameron 65, G 2825.......................... Fishing operation when well
began to kick. While
attempting to control kick,
the stand pipe blew out and
the drilling crew could not
close either of the kelly
valves. Jackup rig was
destroyed and the blowout
continued for 57 days. There
were no injuries.
12/17/82.................... West Delta 70, G 0182............................ Blowout occurred while working
over well with a snubbing
unit. Blowout pushed top of
workstring to a point 30 feet
above the highest object on
the platform. Blowout was
stopped after repeated
attempts to function the shear
rams.
10/20/83.................... Eugene Island 10, G 2892......................... While controlling a kick during
a workover, gas began to leak
from the threads in the
crossover sub and the drill
string safety valve. The leak
increased as the valve was
closed, forcing the
abandonment of the rig. The
well was killed 6 days later.
There was major damage to the
rig but no injuries.
12/3/85..................... West Cameron 648, G 4268......................... Blowout during workover. Crew
unable to stab workstring
safety valve into the
workstring when fluid began
flowing. Three people were
injured trying to stab the
safety valve. The rig was
destroyed and the platform
heavily damaged by fire. The
blowout lasted 47 days. The
Investigation Report
recommended that Order 6 be
revised to require blind-shear
rams in BOP stack during
workovers.
3/20/87..................... Vermilion 226, G 5195............................ Blowout during completion
activities. Blowout through
the drill pipe and drill
string safety valve failed.
The well control team killed
the well by installing blind-
shear rams and shutting in the
well. There were no injuries
and only minor damage during
the 3-day blowout. The
Accident Investigation Report
recommended the installation
of blind-shear rams in BOP
stacks.
5/30/90..................... Brazos A-23, G 3938.............................. Blowout occurred during testing
operations. The blind-shear
rams were closed but failed as
the rig was being jacked up to
clear tubing from the blind
rams. Blind rams were closed
but gas flowed until well
control team killed the well.
There were no injuries and
only minor damages during the
2-day blowout.
9/9/90...................... Eugene Island 296, G 2105........................ During workover operations,
well began to flow through
tubing after running one stand
of collars and one stand of
tubing into the well. Crew
made at least four
unsuccessful attempts to
install full opening safety
valve. The BOPs were closed
but did not stop the blowout.
There were eight injuries and
rig damage during the 4-day
blowout.
[[Page 8408]]
1/24/96..................... Eugene Island 380, G 2327........................ During completion operations,
the well began to flow while
the tubing was extended above
the BOP stack. Crew tried to
stab the top drive into the
top of the tubing but the flow
prevented the connection. The
driller closed the blind rams
to reduce the flow but that
did not help. When gas began
to flow out of the top of the
tubing, the drilling crew
closed the pipe rams and
annular preventer and
evacuated the rig. During the
evacuation of the rig and
platform, the well caught
fire. Fire destroyed the rig
substructure and derrick and
severely damaged other parts
of the rig. MMS investigation
report recommended that blind-
shear rams be required in
surface BOP stacks. (incident
1 in above discussion).
5/31/97..................... East Cameron 83, G 8641.......................... Blowout during completion
operations. Well control team
replaced pipe rams with blind-
shear rams but found that the
tool joint was opposite the
rams. There were no injuries,
pollution, or fire. Well was
out of control for 19 days.
12/2/99..................... SM58, G 01194.................................... Blowout occurred while running
a gravel pack assembly during
completion activities. The
gravel pack was across the BOP
stack when the well began to
flow. The BOP's were closed
but did not stop the blowout.
The well bridged over the next
day.
7/6/01...................... Eugene Island 277, OCS-G 10744................... Blowout occurred during a
workover operation. Well
flowed uncontrolled through
the drill pipe and ruptured
pressure safety valve on the
mud pump. The area around the
rig equipment and drill floor
became inundated with a
hazardous accumulation of gas
and formation sand thus
forcing all personnel to
evacuate to a standby boat.
There were no injuries and
only minor damages to the rig.
(incident 2 in above
discussion).
7/13/01..................... Brazos 417, OCS-G 22190.......................... Blowout occurred during
drilling operations. The well
kicked and flowed up the drill
pipe. The rig floor safety
valve was stabbed but would
not close with two men
applying torque to the handle.
Both men were burned on their
arms and back by the hot mud.
Because of the high
temperature of the mud, the
men had to put on slicker
suits and were sprayed with
water to continue working on
the rig floor. The crew was
ordered to abandon the rig.
After the rig was abandoned,
it was discovered that the
night supervisor was missing.
The Coast Guard searched for
two days but the person was
never found. The BOP stack,
casing and drill pipe were
damaged by high pressure gas
and sand that flowed from the
well. The rig was also damaged
by the gas and sand flow.
(incident 3 in above
discussion).
----------------------------------------------------------------------------------------------------------------
IADC commented that we underestimated the number of blind-shear
rams by approximately 50 percent (80), thus underestimating the costs
by 50 percent. We have reexamined the number of rams that industry
would have to purchase and found that of the rigs currently active or
ready to work, 100 surface BOP stacks did not have blind-shear rams.
When rigs temporarily taken out of service are included, 170 sets of
blind-shear rams would be needed. Part of our low estimate was due to
the increased drilling activity since we prepared the proposed rule and
part was due to a low estimate of the number of blind-shear rams
already installed in surface BOP stacks. Our recent review found that
at least 30 sets of blind-shear rams are currently installed in surface
BOP stacks.
MMS made two assumptions when estimating the cost of upgrading
existing surface BOP stacks to include blind-shear rams. First, it was
projected that all rigs active or ready to work would remain in service
for more than the next 3 years. Second, one-half of the rigs
temporarily taken out of service would be placed back into long term
service over the next 3 years. Increasing the number of blind-shear
rams needed to comply with this requirement to 135 sets will raise
costs estimated in the proposed rule from $14,000,000 to $14,175,000.
The original cost per set of blind-shear rams was overstated
($175,000), and has been reduced ($105,000) according to information
obtained recently from BOP manufacturers. Given the number of rams that
industry will have to purchase, MMS has allowed a 3-year timeframe for
installing the rams versus the 1-year timeframe identified in the
proposed rule. This 3-year period will allow industry sufficient time
to plan the acquisition and installation of this critical safety
equipment. The following table summarizes the costs associated with
this requirement.
----------------------------------------------------------------------------------------------------------------
Cost to small
Requirement Total cost Annual costs businesses
----------------------------------------------------------------------------------------------------------------
Proposed Rule--Install blind-shear rams $14,000,000 $14,000,000 over 1 year........... $0
within 1 year.
Final Rule--Install blind-shear rams 14,175,000 4,725,000 over 3 years............ 0
within 3 years.
----------------------------------------------------------------------------------------------------------------
Avoidance of future blowout related costs, through the installation
of blind-shear rams on all existing drilling rigs with surface BOP
stacks, would constitute the potential benefits to lessees and their
drilling contractors. In the analysis conducted for this rule, gross
benefits are partially offset by the costs to purchase and install
blind-shear rams, in surface BOP stacks that don't already have them.
Our analysis indicates that implementation of the regulation will most
likely result in net present value benefits to lessees and drilling
contractors of $22 million. These benefits can be achieved by investing
in the acquisition and installation of blind-shear rams for a present
value cost of $13 million. Accordingly, the present value of gross
industry benefits from this regulation will most likely be $35 million.
As discussed in the proposed rule, we believe that the final rule
will not have a significant impact on small drilling contractors. It
won't impact small drilling contractors because there is only one that
qualifies as a small business, and that contractor has already equipped
its surface BOP stacks with blind-shear rams. The drilling contractor
indicated that the blind-shear rams were installed as an additional
safety precaution.
IADC also commented that MMS did not consider the consequences of
the
[[Page 8409]]
inadvertent operation or malfunction of the blind-shear rams in the
proposed rule. We know industry has many years of experience with
having blind-shear rams in subsea BOP stacks and that industry has
developed safeguards and procedures to prevent the inadvertent
operation of this equipment. Also, several operators have many years of
experience of having blind-shear rams in surface BOP stacks in the GOM.
MMS, therefore, is confident that industry can adequately safeguard the
BOP control panels and adequately train its personnel to prevent the
inadvertent operation of blind-shear rams.
MMS disagrees with IADC's comment that the successful operation of
blind-shear rams permanently forecloses other well control options.
Many wells have been controlled after blind-shear rams shut them in. At
least four of the wells identified in the table above regained control
of the well by lubricating heavyweight drilling fluids into the annulus
to kill the well (8/4/78; 10/5/81; 5/15/82; 3/20/87). While lubricating
or bullheading fluids into a live well may not be the preferred method
for regaining control of a well, it is better than losing total control
of the well.
Finally, one commenter indicated that the operating limits of
blind-shear rams are frequently unclear for some drilling operations
due to pipe grades, mud weights, and wellbore pressures, and that
consideration should be given to ensure that these limits are clear. We
agree that this is important, so we have added a paragraph to Sec.
250.416(e) that requires the lessee to address these issues. The new
paragraph requires the lessee to provide information that shows that
the blind-shear or shear rams installed in the BOP stack (both surface
and subsea stacks) are capable of shearing the drill pipe in the hole
under maximum anticipated surface pressures.
[sbull] Comment on Sec. 250.441 What are the requirements for a
surface BOP stack? MMS should revise the rule to allow an exception for
less than four remote-controlled BOPs.
Response: Because you may include this request in your APD
submission to the District Supervisor, we did not revise the rule to
allow the use of less than four remote-controlled BOPs in certain
situations.
[sbull] Comment on Sec. 250.442 What are the requirements for a
subsea BOP stack? One commenter asked why didn't MMS identify the costs
associated with the subsea accumulator requirements.
Response: MMS did not specify any costs for this requirement
because lessees/operators were already required by the regulations to
have an accumulator that provided for fast closure. API RP 53 now
provides guidelines for determining the minimum requirements and
performance for the subsea accumulator.
[sbull] Comment on Sec. 250.442 What are the requirements for a
subsea BOP stack? A commenter noted that section 13.3 of API RP 53 does
not include subsea accumulator volume requirements that can be audited
other than the specific response times.
Response: MMS will review BOP test records, including documentation
of the closing times of ram and annular preventers, in evaluating BOP
system performance.
[sbull] Comment on Sec. 250.443 What associated BOP systems and
related equipment must my BOP system include? MMS should clarify that
this section applies to both surface and subsea BOP equipment. The
commenter also recommended that MMS consider adopting more sections of
API RP 53 and/or API RP 16E instead of having a number of the specific
requirements stated in the BOP system sections (250.440 to 250.451).
Adoption of these documents would provide a more rigorous standard than
the current MMS requirements.
Response: We clarified the intent of this section by revising the
title to read ``What associated BOP systems and related equipment must
my surface and subsurface BOP systems include?'' MMS will consider
incorporating additional sections of API RP 53 and API RP 16E or
possibly the entire document in possible future revisions of the
drilling regulations.
[sbull] Comment on Sec. 250.446 What must I do to maintain and
inspect my BOP? MMS should consider incorporating parts of other
quality management standards into the regulations, such as API Q1's,
``The supplier shall establish and maintain documented procedures for
implementing corrective and preventive action * * * and API Spec 16A's,
Appendix G, ``The operator of drill through equipment manufactured to
this specification shall provide a written report to the equipment
manufacturer of any malfunction or failure which occurs * * *''
Response: The quality management program incorporated by sections
17.12 and 18.12 in API RP 53 pertains to a planned maintenance system
for BOP equipment and to maintaining copies of equipment manufacturer's
product alerts and bulletins. The purpose for incorporating these
sections was to ensure that BOP equipment is maintained properly. It
was not to require equipment specifications or certification
requirements for BOP equipment. MMS believes that incorporation of the
specific sections of API RP 53 will meet the objective of identifying
appropriate maintenance requirements.
[sbull] Comment on Sec. 250.448 What are the BOP pressure tests
requirements? MMS requirements for a low-pressure test provide a lower
acceptance standard when compared to sections 17.3.2 and 18.3.2. MMS
should consider incorporating these sections into the regulations.
Response: These sections of API RP 53 state the following on low-
pressure tests: ``When performing the low pressure test, do not apply a
higher pressure and bleed down to the low test pressure. The higher
pressure could initiate a seal that may continue to seal after the
pressure is lowered and, therefore, misrepresenting a low pressure
condition.'' MMS recognizes that this situation could occur on a low-
pressure test, but we also recognize that it may be difficult to
precisely apply 200 to 300 pounds per square inch (psi) to the
component to be tested. Based on our experience and judgment, we have
allowed operators to conduct a low-pressure test (200 to 300 psi) if
the initial pressurization did not exceed 500 psi. Any pressure higher
than 500 psi must be bled to zero and the test reinitiated.
[sbull] Comment on Sec. 250.448 What are the BOP pressure tests
requirements? MMS should consider testing ram preventers at an
intermediate pressure, which ranges between 2,000 and 4,500 psi
depending on closing ratio, because it provides a better measure of
fitness for purpose. This intermediate pressure is another possible
mode of failure. These intermediate pressure tests would be conducted
initially and on an annual basis.
Response: MMS is unlikely to require such a test until it becomes
an accepted industry practice.
[sbull] Comment on Sec. 250.449 What additional BOP testing
requirements must I comply with? The requirement for variable bore rams
(VBRs) to pressure test against all sizes of pipe may be more rigorous
than the largest and smallest sizes as recommended by API RP 53
(sections 17.5.5 and 18.5.5).
Response: We have revised the requirement in Sec. 250.449(f) to
now require you to pressure test VBRs against the largest and smallest
sizes of pipe in use, excluding drill collars and bottom-hole tools.
This conforms to API RP 53 recommended practice. Also, one of the
findings from a 1999 research project, ``Reliability of Subsea BOP
Systems for Deepwater Application, Phase II DW, by Per Holand of SINTEF
Industrial Management,'' recommended
[[Page 8410]]
that we should not require testing VBRs on all sizes. The rationale was
that the testing of VBRs on all sizes adds very little to increased
safety availability in the BOP due to the redundancy in the stack, and
that most failures will occur during the pressure test.
[sbull] Comment on Sec. 250.449 What additional BOP testing
requirements must I comply with? Mandatory pressure testing of the BOP
system after landing is not justified considering the extremely low
failure rate of BOP components and the fact that the physical act of
running the stack imposes little to no stress on the functional
components of the BOP system. After a successful stump test, MMS should
require only a function test for the BOP stack once it is on bottom.
Function testing after landing will ensure that all control circuits
are operating properly. This minor revision has a potentially huge
beneficial impact by saving lost rig time to the initial BOP pressure
test.
Response: We did not revise this requirement as suggested. We
believe that the initial pressure test of the BOP stack after landing
on the well is critical to ensuring that it functions properly. The
results from our 1999 research project on the reliability of deep water
subsea BOP systems (Holand, 1999) support our belief. That research
project examined data from 83 wells that were drilled using subsea BOP
stacks in the deep water GOM. The majority of the wells were spudded
during July 1, 1997, to May 1, 1998. The results showed that 15
components failed during the initial pressure tests after the BOP stack
landed on the wellhead. Of those 15 failures, 10 were in the control
systems and may have been discovered in a function test. However, five
other failures occurred (two connectors, one annular preventer, one ram
preventer, one choke and kill valve) that may not have been discovered
without the initial pressure test. MMS will continue to require the
initial pressure test after landing the subsea BOP stack.
[sbull] Comment on Sec. 250.456 What are the required safe
drilling fluid program practices? Paragraph (a) should not require
circulating the well before starting out of the hole if you have lost
circulation.
Response: MMS believes that pipe should not be pulled out of the
hole until a loss circulation pill has been spotted and the well is
under control. It is recommended that the top part of the hole be
circulated to ensure that the wellbore is clear of gas. Some loss of
returns is acceptable while pulling out of the hole; however, excessive
loss circulation would require remaining on bottom until the loss was
controlled either with a pill or cement.
[sbull] Comment on Sec. 250.456 What are the required safe
drilling fluid program practices? Recommend that MMS eliminate the
second sentence in paragraph (e) which says ``You must circulate and
condition the well, on or near-bottom, unless well or drilling-fluid
conditions prevent running the drill pipe back to the bottom.'' The
first sentence of this requirement which says you must take appropriate
measures to control the well is sufficient to address this situation.
Response: We did not remove the second sentence of this paragraph
because this is a safe drilling practice. However, the sentence in
question does allow for not running drill pipe to bottom to circulate
the well if conditions prevent it.
[sbull] Comment on Sec. 250.456 What are the required safe
drilling fluid program practices? Recommend that paragraph (f) allow
the District Supervisor the discretion to not require the posting of
the surface pressure at which the shoe would break down.
Response: We did not revise this paragraph. You may request a
departure from this requirement in your APD submission to the District
Supervisor.
[sbull] Comment on Sec. 250.456 What are the required safe
drilling fluid program practices? MMS should allow the District
Supervisor the discretion to not require degassers in all situations
(paragraph (g)).
Response: We did not revise this paragraph. You may request a
departure from this requirement in your APD submission to the District
Supervisor.
[sbull] Comment on Sec. 250.458 What quantities of drilling fluids
are required? The commenter prefers the current wording over the
proposed wording.
Response: The new regulations use a more active style of writing
versus the passive style used in the previous regulations. The
requirements (and most of the words) are the same.
[sbull] Comments on Sec. 250.459 What are the safety requirements
for drilling-fluid-handling areas? The two drilling contractors and
IADC commented that the requirement to classify drilling-fluid-handling
areas according to API RP 500, Recommended Practice for Classification
of Locations for Electrical Installations at Petroleum Facilities, is
in conflict with the 1998 MMS/USCG MOU as it relates to MODUs. The MOU
assigns regulatory oversight of this subject matter to the USCG. USCG
regulations at 46 CFR 108.170 and 108.187 clearly address these
matters, as do the Classification Society requirements applicable to
MODUs. Accordingly, the requirements in this section should not apply
to MODUs.
Response: This is not a new requirement. The USCG is responsible
for the inspection on this area for electrical requirements; it is
classified due to a possible source for gas coming out of the cuttings.
MMS inspects for gas detectors and tests them on a regular basis. If we
see anything that does not meet the USCG's requirement, such as an
exposed wire, then MMS would shut down operation and require that it be
repaired. All drilling-fluid-handling areas are treated the same.
[sbull] Comment on Sec. 250.460 What are the requirements for well
testing? These requirements should not apply if a well test is
conducted on a permanent production facility.
Response: Your projected plans for a well test on a permanent
production facility must address all appropriate requirements. You may
reference another document or plan if it addresses a specific
requirement, such as the description of safety equipment.
[sbull] Comment on Sec. 250.465 When must I submit sundry notices
to MMS? An open hole sidetrack to go around junk in the hole and to
continue drilling to the original approved APD should not require a
sundry notice.
Response: All sidetracks require the submittal of a sundry notice,
and the API number is incremented. This allows the logs to be tracked
and handled correctly.
III. OOC Comments on Specific Sections
The following table contains the OOC's unedited comments on the
proposed requirements for oil and gas drilling operations and our
response to those comments. In this table, we have italicized words
that OOC wanted added to the regulations and have bracketed words that
the OOC wanted deleted from the regulations.
[[Page 8411]]
----------------------------------------------------------------------------------------------------------------
Proposed section OOC comments OOC rationale MMS response
----------------------------------------------------------------------------------------------------------------
250.198........................ Incorporate correct By Federal Register The final rule references
editions of API RP 500 Notice dated January 4, the correct documents
and API RP 505 into the 2000, MMS incorporated and editions.
regulations. by reference API RP 500,
Second Edition and API
RP 505, First Edition.
Proposed Rule should be
modified to state such.
250.401(b)..................... (b) Have a person onsite Include 24 hours a day to We did not add the 24
24 hours per day during provide clarity. hours per day because it
operations that is unnecessary, but we
represents your did add during
interests and can operations as suggested.
fulfill your
responsibilities.
250.401(c)..................... (c) Ensure that the Well may go from drilling We made the suggested
toolpusher or a member to completion and not be changes.
of the drilling crew abandoned. Additionally,
maintains continuous bridge plugs and cement
surveillance of the rig plugs are viable options
floor from the beginning for securing the well.
of drilling operations
until the well is
abandoned or completed,
unless you have secured
the well with blowout
preventers (BOPs),
bridge plugs, cement
plugs, or packers.
250.402........................ When and how must I The use of the phrase We made the suggested
secure a well? Whenever ``as deep as possible'' changes.
you interrupt drilling infers that the device
operations, you must should be set at the
install a downhole bottom of the hole. By
safety device, such as a changing ``as deep as
cement plug, bridge possible'' to ``an
plug, or packer. You appropriate depth''
must install the the allows the operator
device [as deep as flexibility to choose
possible] at an appropriate setting
appropriate depth within depths.
a properly cemented
casing string or liner.
250.402(a)..................... (a) [Among] The events The proposed text We did not make the
that may cause you to regarding what types of suggested change because
[interrupt] temporarily events require securing there may be other
suspend drilling of well downhole is events that cause you to
operations or. vague and open-ended. interrupt drilling
Therefore, we recommend operations. The wording
the word ``among'' in as suggested would limit
paragraph (a) be the events that would
deleted, and the require the installation
remainder of the of a downhole safety
paragraph be amended as device.
recommended to detail
the specific type of
events, which is
consistent with existing
requirements.
250.403(c)..................... Requested clarity for The language proposed is We revised the wording to
paragraph (c) When you very vague. It appears clearly state when you
move a drilling rig or that a subsurface shut- must shut in each well
related equipment on a in is only required to below the surface and at
platform. You must shut move a rig while located the wellhead. The final
in each well below the on a platform (i.e. from wording is contained in
surface and at the well to well) and does Sec. 250.406.
wellhead, unless not address rigging-up
otherwise approved by and rigging-down. Also
the District Supervisor. applicability to MODUs
is unclear (movement of
cantilever jack-ups and
floaters).
250.410(b)(3).................. Form MMS-123S may require We assume that Form MMS- As previously discussed,
modifications to include 123S will be modified to MMS revised this form
additional information contain new information and the other subpart D
requirements. OOC requirements. Therefore, drilling and well forms
requests that it be we believe it would be through a separate
allowed to review and beneficial to both process. We provided an
provide comments to the industry and the MMS to opportunity to comment
MMS, if the form is allow OOC to review the on the revised forms and
modified. new form. note that OOC did
comment.
250.413(h)..................... (h) delete............... We recommend that Line The revised paragraph (h)
(h) be deleted. It is now says that your well
not clear how is this drilling design criteria
additional summary is to must include a summary
be submitted. (i.e. Is report of the shallow
it to be included in hazards site survey if
Form MMS 123S or is it a it was not previously
narrative summary to submitted.
part of the ADP, or is
it a separate
submittal?) The language
as proposed is unclear,
and OOC is not sure of
the intent, or the
purpose of this
additional reporting
requirement.
Additionally, the
summary report of the
shallow hazards site
survey will have been
previously submitted
with the EP/DOCD under
which the well will be
drilled.
[[Page 8412]]
250.414 (a), (b), (d), (e), (f) Clarity is requested for Currently the majority With the exception of
and (g). lines (a), (b), (d), this of data is captured providing the estimated
(e), (f) and (g)--What in the APD Information depths to faults, these
items must my drilling Spreadsheet. However, requirements were
prognosis include? (a) will the proposed form contained in Sec.
Projected plans for MMS-123S include other 250.415(f)(5) of the
coring at specified required data, such as current regulations. You
depths; (b) Projected estimated depths to the may use form MMS-123S to
plans for logging; (d) top of significant provide as much of this
Estimated depths to the marker formations, major information as
top of significant faults, etc? OOC assumes appropriate. Information
marker formations; (e) that the intent of the you do not include on
Estimated depths to requirement is to that form must be
significant porous and identify faults that can included with the
permeable zones potentially lead to drilling prognosis. As
containing fresh water, problems while drilling. for estimating the
oil, gas, or abnormally Therefore, it is depths to faults, we
pressured formation recommended that the made the suggested
fluids; (f) Estimated language be modified to change to require only
depths to major faults; include major faults the estimated depths to
and (g) Estimated depths only. major faults.
of permafrost, if
applicable.
250.415(a)..................... Hole sizes and casing The requirement for We made this suggested
sizes, including: including the tension change. We will continue
weights; grades; value has been deleted to require the tension
[tension] collapse, and from the proposed casing design safety
burst values; types of language. This factor which is covered
connection; and setting information has not been in paragraph (b).
depths (measured and required in the past.
TVD). The need to now require
this information is
unclear. If this
requirement remains,
will the ADP Information
Spreadsheet/form MMS-
123S, be revised to
capture these values?
250.417(a)..................... (a) If sufficient Clarity. The proposed We added the phrase
environmental language is too broad ``during operations'' to
information and data are and does not present the requirement as
not available, the under which conditions suggested. We did not
District Supervisor may the additional data add the second sentence
require you to collect would be required. because it is
and report this unnecessary. The context
information during the of the section sets the
period of operation. The limits for the type of
information to be information to be
collected and reported collected.
will be related to the
structural integrity of
the drilling unit and
the safe conduct of
operations.
250.417(b)..................... (b) The District Clarity. The proposed The sentence was revised
Supervisor may require language is too broad as follows: The District
you to conduct and does not present Supervisor may require
additional surveys and under which conditions you to conduct
soil borings before the additional data additional surveys and
approving the APD, if would be required. soil borings before
the District Supervisor approving the APD if
cannot make a additional information
determination that the is needed to make a
proposed drilling unit determination that the
can be supported at the conditions are capable
specific site. of supporting the
drilling unit.
250.420(b)(1).................. (b) Casing Requirements. OOC recommends that the We did not make the
(1) You must design phrase ``and suggested change. This
casing (including combinations thereof'' is not a new requirement
liners) to withstand the be deleted because this (currently in Sec.
anticipated stresses statement is vague as to 250.404(a)(3)). You must
imposed by tensile, what combinations must design casing to
compressive, and be considered. withstand all
buckling loads; burst combinations.
and collapse pressures;
thermal effects[; and
combinations thereof].
250.420(b)(2).................. (2) The casing design OOC recommends that the We did not make the
must include safety phrase ``and safe suggested change. You
measures that ensure operations during the must design your casing
well control during life of the well'' be for the life of the
drilling [and safe deleted because it is well.
operations during the too broad.
life of the well].
250.421(b)..................... (b) Use enough cement to Cement in the annular We did not make this
fill the annular space area between the suggested change.
back to the mud line. conductor and the drive/ Washing out or
Verify annular fill by structural pipe can displacing cement is
observing cement cause difficulty in covered by Sec.
returns. If you cannot cutting pipe and 250.418(g). That
observe cement returns, clearing the location paragraph now says that
use additional cement to below the mud line. washing out cement must
ensure fill back to the be addressed in the APD.
mud line. Excess cement
may be washed out from
the annulus below the
mud line to a sufficient
depth as necessary to
facilitate well
abandonment operations.
For drilling * * *.
[[Page 8413]]
250.421(f)..................... If you use a liner as It is common practice to We did not make the
conductor or surface achieve the liner-lap suggested change of
casing, you must set the lengths discussed adding ``unless
top of the liner at herein. However, there otherwise approved by
least 200 feet above the are instances when this the District
previous casing/liner is undesirable and, in Supervisor.'' In fact,
shoe. If you use a liner those cases, a liner top we have removed that
as an intermediate or packer is typically phrase from many
production casing, you installed to ensure a sections because it is
must set the top of the good seal. The unnecessary. The
liner at least 100 feet recommended language District Supervisor has
above the previous change will provide the the flexibility to
casing shoe, unless District Supervisor the approve many requests
otherwise approved by flexibility to approve a without that phrase in
the District Supervisor. shorter liner-lap. the regulations. To
emphasize this
flexibility, we have
added to the drilling
regulations two
sections: Sec.
250.408, ``May I use
alternative procedures
or equipment during
drilling operations?'',
and Sec. 250.409,
``May I obtain
departures from these
drilling requirements?''
250.421(f)..................... * * * If you use a liner Existing regulations We have revised this
as an intermediate or include language that paragraph to read ``If
production casing, you prohibits the use of a you use a liner as an
must set the top of the production liner when intermediate string
liner at least 100 feet landed in a surface below a surface string
above the previous casing. Is this no or production casing
casing shoe. longer the case?. below an intermediate
string, you must set the
top of the liner at
least 100 feet above the
previous casing shoe.''
MMS does not allow
production liner to be
set inside the surface
casing, thereby to be
used for production
except in very limited
conditions. Each such
liner set departure must
be individually
reviewed.
250.422(b)..................... When may I resume The term ``in advance'' We made the following
drilling after in the proposed text is changes to this
cementing? * * * (b) If very vague. We recommend requirement: We replaced
you plan to nipple down it be removed and the the phrase ``in
your diverter or BOP actual information advance'' with ``before
stack during the 8- or necessary to make the nippling down'' because
12-hour waiting time, determination be stated. we wanted to ensure that
you must determine, [in However, we do agree no one made the
advance] when it will be that the performance- determination after
safe to conduct this based language as nippling down. We
activity. Your written in Sec. revised the last
determination must be 250.422(b) is sentence of the
based on a knowledge of appropriate. That is, requirement to include
formations conditions making the operator most of the wording
encountered, presence of responsible for suggested.
potential drilling assessing when it is
hazards, actual well safe to nipple down well
conditions while control equipment. As a
drilling, cementing and prudent operator, this
post cementing as well assessment is made based
as past experience. on a knowledge of
formations conditions
encountered, presence of
potential drilling
hazards, actual well
conditions while
drilling, cementing and
post cementing as well
as past experience.
250.423(b)..................... (b) Change casing setting It is recommended that We changed this paragraph
depths more than 100 approval be obtained if to allow an increase of
feet TVD from the the casing depth change casing setting depth of
approved APD. is more than 100 feet up to 100 feet total
TVD, not measured depth. vertical depth before
Additionally, if the requiring a submittal to
casing becomes stuck the District Supervisor.
while running or other In the case where the
hole conditions prevent casing setting depth
the running of casing to fell short of the
the projected setting planned depth, you would
depth, the operator have to contact the
should be allowed to District Supervisor only
cement the casing if the well conditions
without seeking warranted revising your
approval, and notify the casing design (see Sec.
District Supervisor 250.423(a)).
subsequently.
250.423(h)..................... Submit geologic data and The 500-foot limit is too We did not make the
information to the prescriptive. This suggested change. The
District Supervisor that waiver should be based 500-foot distance was
demonstrates the absence on the geologic data selected by MMS
of shallow hydrocarbons from an applicable geologists and drilling
or hazards. This analogous well. engineers as a
information must include reasonable distance. MMS
logging, [and] drilling can best serve the
fluid-monitoring and industry by keeping the
other available geologic 500-foot distance in the
data from wells regulations (see Sec.
previously drilled 250.428(g)).
[within 500 feet] in the
immediate vicinity of
the proposed well path
down to the next casing
point.
[[Page 8414]]
250.424(a)..................... (a) You must pressure There is more than one We chose not to list the
test each string of currently approved alternative methods for
casing to 70 percent of method for calculating calculating casing test
its minimum internal casing test pressure. We pressure. You should
yield or as otherwise recommend that the address alternative test
approved by the District alternative test methods pressures or methods in
Supervisor. This testing be included in the new your APD (see Sec.
requirement does not requirements, or allow 250.423).
apply to drive or the District Supervisor
structural casing. When the discretion to
a diverter is installed approve alternative
on conductor casing, you methods.
must test the casing to
a minimum of 200 psi.
[The District Supervisor
may approve or require
other casing test
pressures.]
250.431(a)..................... (a) Use diverter spool API line pipe is normally We made the suggested
outlets and diverter used for diverter lines. changes.
lines that have [an Line pipe is different
internal diameter] a than casing. The nominal
nominal diameter of at size of line pipe
least 10 inches for normally refers to the
surface wellhead OD (for larger sizes).
configurations and at
least 12 inches for
floating drilling
operations.
250.434........................ (f) After drilling is To require the lessee to We deleted paragraph (f)
completed, [retain all maintain detailed and moved the
the records listed in drilling records at the recordkeeping
this section for 2 years facility or at the requirements to Sec.
at the facility, at the nearest field location Sec. 250.466 and
lessee's field office after drilling is 250.467. Section 250.466
nearest to the facility, completed is requires you to keep
or at another location unreasonable, and places drilling records onsite
conveniently available an unnecessary during drilling
to the District recordkeeping burden on operations. After
Supervisor.] the lessee the operator. We do completion of drilling
must retain all the maintain these records; activities, you may keep
records listed in this however, they are all records at a
section for 2 years and typically maintained in location of your choice.
make them available at a central record center. A table in Sec.
the District The need to maintain 250.467 gives the time
Supervisor's request. test results in the periods for keeping all
field after the drill records.
operations are completed
is unclear. Should the
need to review these
records arise, they can
be supplied at that time.
250.440........................ You must design, install, Include test in the We made the suggested
maintain, test and use proposed text to be change.
the BOP system and complete and consistent
system components to with the existing
ensure well control * * requirements.
*.
250.441(b)..................... (b) Delete............... We strongly recommend MMS did not make the
that this requirement be suggested change. See
eliminated. We have response to comments in
reviewed the description the previous part of the
of the incidents used by preamble.
the MMS to justify the As for the $150,000 cost
proposed requirement to per stack cited by OOC,
install blind-shear rams we have used a cost of
in all BOP stacks and $175,000 in our
disagree with the evaluation of impacts.
conclusion that they
support the need to
require the installation
of blind-shear rams.
Furthermore, a 13\5/8\
inch blind-shear rams
would cost the drilling
contractor an estimated
$82,000 plus
transportation and
installation costs. The
total estimated cost
imposed by this
requirement would be
$150,000 per stack.
250.442(b)..................... (b) You must install a Many BOP stacks on Our changes to this
subsea accumulator floating drilling rigs paragraph follow the
closing unit, or currently in operation suggested changes (see
equivalent systems to do not meet the proposed Sec. 250.442(c)).
provide fast closure of requirement to install a
the BOP components and subsea accumulator. In
to operate all critical lieu of subsea
functions in case of a accumulators, the
loss of the power fluid inclusion of redundant
connection to the power/control lines
surface. The [subsea] provides the equivalent
accumulator must meet or protection necessary.
exceed the provisions of Therefore, we recommend
Section 13.3, the inclusion of the
Accumulator Volumetric statement ``or
Capacity, in API RP 53, equivalent system'' to
Recommended Practice for the proposed language.
Blowout Prevention
Equipment Systems for
Drilling Wells. The
District Supervisor may
approve a suitable
alternative method.
[[Page 8415]]
250.442(d)..................... (d) Before removing the Drillships and semi We did not make this
marine drilling riser, submersible drilling suggested change. MMS
you must displace the rigs with automatic realizes that during an
riser with seawater, station keeping (ASK) emergency you will not
except in the case of an systems may experience be able to displace the
emergency riser ASK failures at which riser with seawater, but
disconnect, You must* * time the well must be this specific case does
*. isolated with the BOP not need to be addressed
and the marine riser in the regulations (see
disconnection Sec. 250.442(e)).
immediately to prevent
damage to well,
equipment, and rig. It
is therefore impractical
to displace the marine
riser with seawater
prior to an emergency
riser disconnect.
250.447(b)..................... (b) Before 14 days have More frequent testing We did not make the
elapsed since your last without a specified suggested change. MMS
BOP pressure test, you interval is too broad. sees no reason to set a
must begin to test your fixed BOP testing
BOP system before interval for when the
midnight on the 14th day District Supervisor may
following the conclusion require more frequent
of the previous test. testing. MMS may choose
However, the District a test interval between
Supervisor may [require 7 and 14 days depending
more frequent testing] on conditions or
require the test to be performance. BOP
performed before performance that
midnight on the 7th day warrants testing at less
following the conclusion than 7-day intervals
of the previous test, if would likely lead to
conditions or BOP shutting in the drilling
performance warrant; and unit until you fix the
problems.
250.448(b)..................... (b) High Pressure tests OOC recognizes and MMS will not publish a
for ram type * * * appreciates MMS efforts list of acceptable
Clarity requested. to allow for BOP high- methods to calculate
pressure tests MASP in the regulations.
requirements to include We don't believe that it
either testing to rated is appropriate to limit
working pressure, or to the number of acceptable
500 psi above the methods nor do we
maximum allowable believe that such a list
Surface Pressure (MASP) would provide clarity.
for the applicable
section of the hole.
However, we recommend
that the proposed rule
include acceptable
methods for calculating
MASP, to provide clarity.
250.448(c)..................... (c) High pressure test Currently approved We changed the paragraph
for annular-type BOPs. procedures for testing to read ``The high
The high pressure test annular preventers allow pressure test must equal
must equal 70 percent of for testing to a 70% of the rated working
the rated 70 percent of pressure less than 70% pressure of the
the rated working of the working pressure, equipment or to a
pressure of the such as testing to the pressure approved in
equipment, or as MASP. your APD.''
otherwise approved by
the District Supervisor.
250.450(c)..................... (c) Document the The requirement to record Section 250.442(c)
sequential order of BOP closing times should be requires that ``the
and auxiliary equipment removed. This accumulator system
testing and the pressure requirement is not a equipment must meet or
and duration of each common practice. exceed the provisions of
test. [For subsea BOP Furthermore, there is no Section 13.3,
systems, you must also requirement for maximum Accumulator Volumetric
record the closing times closing time of a BOP, Capacity, in API RP
for annular and ram and it is unclear how 53.'' Section 13.3.5 in
preventers.] You may the measurement of API RP 53 says ``For
reference a BOP test closing time would be subsea installations,
plan if it is available determined (is it from the BOP control system
at the facility. the time the button is should be capable of
pushed until the fluid closing each ram BOP in
flow stop, or the time 45 seconds or less.
it takes the ram to Closing should not
fully stroke?). We do exceed 60 seconds for
not see the value added annular BOPs.'' As
by recording this time. discussed in the
Either, a BOP stack preamble of the proposed
functions properly or rule, we incorporated
not. API RP 53 by reference
so that both industry
and MMS would have
guidelines for
determining the minimum
requirements and
performance standards
for subsea accumulators
and BOP systems. As for
the measurement of
closing times, the RP
states that ``the
measurement of closing
response time begins at
pushing the button or
turning the control
valve handle to operate
the function and ends
when the BOP or valve is
closed, effecting a
seal. A BOP is
considered closed when
the regulated operating
pressure has recovered
to its nominal
setting.''
[[Page 8416]]
250.450(g)..................... (g) After drilling is To require the lessee to We deleted paragraph (g)
completed, [retain all maintain detailed and moved the record-
the records listed in drilling records at the keeping requirements to
this section for 2 years facility or at the Sec. Sec. 250.466 and
at the facility, at the nearest field office 250.467. See previous
lessee's field office nearest field location discussion on Sec.
nearest to the facility, after drilling 250.434.
or at another location operations are completed
conveniently available is unreasonable, and
to the District places an unnecessary
Supervisor.] the lessee recordkeeping burden on
must retain all the the operator. We do not
records listed in this maintain these records;
section for 2 years and however, they are
make them available at typically maintained in
the District a central record center.
Supervisor's request. The need to maintain
test results in the
field after the drill
operations are completed
is unclear. Should the
need to review these
records arise, they can
be supplied at that time.
250.457(a)..................... (a) You must have and There are many times on a We agree with the comment
maintain drilling fluid- rig when circulation and moved the paragraph
testing equipment on the does not occur during a to become Sec.
drilling rig at all tour, or longer, and 250.456(i). The new
times. You must test the testing twice per day paragraph says: ``When
drilling fluid, when (once each tour) has no circulating, you must
circulating at least added value. Therefore, test the drilling fluid
once each tour or more we recommend that this at least once each tour
frequently if conditions be a requirement during or more frequently if
warrant. You must circulation only. conditions warrant. You
perform the tests Furthermore, the tests must conform to
according to industry- proposed text is too industry-accepted
accepted practices. broad in regards to what practices and include
Tests must include type and why might the density, viscosity, and
density, viscosity, and District Supervisor gel and gel strength;
gel strength; require additional test. hydrogenion
hydrogenion The recommended language concentration;
concentration; is consistent with the filtration; and any
filtration; and any existing requirements. other tests the District
other tests the District Supervisor requires for
Supervisor requires for monitoring drilling
monitoring and fluid quality,
maintaining drilling prevention of downhole
fluid quality for safe equipment problems and
operations, prevention for kick detection. You
of downhole equipment must record . . . .''
problems and for the
detection of kicks. You
must record * * *.
250.460(a)..................... Clarity requested........ The proposed language is We agree with the comment
confusing. The title of that the two paragraphs
this section is ``What don't fit under this
are the requirements for title. We moved
well testing?'' However, paragraph (a) to its own
paragraph (a) discusses section (now Sec.
determining formation 250.407 ``What tests
characteristics using must I conduct to
formation fluid samples determine reservoir
and logging. It seems characteristics?)''
appropriate to put this under general
paragraph in a section requirements. We then re-
titled ``what type titled this section
samples, survey and ``What are the
tests of the formation requirements for
are required.'' Please conducting a well
refer to 30 CFR test?''
250.401(e) in the
existing regulations.
250.461(a)..................... (a) Survey requirements Digitally recording We made the suggested
for a vertical well: (1) inclination surveys changes.
You must conduct while drilling a
inclination surveys on vertical well is not
each vertical well and necessary or practical.
[digitally] record the Inclination surveys are
results. Survey used as a process
intervals may not exceed control check to ensure
1,000 feet during the that the well remains
normal course of near vertical. The
drilling. (2) You must subsequent surveys,
also conduct a which include both
directional survey that inclination and azimuth,
provides both can be digitally
inclination and azimuth, recorded in electronic
and digitally record the format. The phrase
results in electronic ``electronic format''
format: has been add to clarify
that the record should
be stored electronically
for submittal to MMS,
not record as
``fingers'' on a paper
copy.
250.461(e)..................... (e) If you drill within The adjacent leaseholder We revised the paragraph
500 feet of an adjacent should request the by adding the following
lease, the Regional survey. sentence: ``This could
Supervisor may require occur when the adjoining
you to furnish a copy of leaseholder requests a
the well's directional copy of the survey for
survey to the affected the protection of
leaseholder, if the correlative rights.''
leaseholder has
requested the survey.
250.462(d)..................... (d) MMS ordered drill. An Clarifies who will be We made the suggested
MMS authorized consulted prior to change.
representative. The MMS conducting the drill.
representative will
consult with your onsite
representative before
requiring the drill.
[[Page 8417]]
250.465(a)(1).................. Receive written or oral With weekends and We made the suggested
approval from the holidays, it is often change.
District Supervisor difficult to meet the 72-
before you begin the hour limitation.
intended operation. If
you get an oral
approval, you must
submit form MMS-124
[within 72 hours] no
later than the end of
the 3rd business day
following the oral
approval. In all cases,
you must meet the
additional requirements
in paragraph (b) of this
section.
250.466(g)..................... (g) All other information Proposed language is very We made the suggested
required by the District broad. The recommended changes.
Supervisor in order to language clarifies under
evaluate resource what circumstances will
evaluation, waste additional information
prevention, conservation be requested.
of natural resources,
protection of
correlative rights,
safety or protection of
the environment.
250.467........................ Delete section........... As written, this section We renumbered this
appears to be for section to 250.469. The
informational purposes, purpose of this section
rather than a is to inform you what
requirement. records the District
Furthermore, the Supervisor may require
proposed language is you to submit. The
vague. Line (a) paragraphs identify the
discusses an NTL; Line following: (a) well
(b) Specifies records, (b)
requirements for GOMR, paleontological reports
but is silent on and states that the
requirements for other Regional Supervisor may
regions. Line (c) as issue a Notice to
written appears that Lessees that prescribes
this is not mandatory, the manner, timeframe,
but at the discretion of and format for
the District Supervisor, submitting this
and Line (d) eliminates information, and (c)
the prescriptive service company reports.
requirements for We moved the
legible, exact copies of requirements to submit
service company records. form MMS--133, Well
Activity Report, and
daily drilling reports
to the mandatory Sec.
Sec. 250.468(b) and
(c).
250.515 (b) and 250.615 (b).... Delete this requirement.. Please refer to rationale MMS did not make the
previously discussed in suggested change. See
Section 250.441 of this our response to comments
document. for Sec. 250.441.
----------------------------------------------------------------------------------------------------------------
Procedural Matters
Regulatory Planning and Review (Executive Order 12866)
The Office of Mangement and Budget (OMB) has designated this a
significant rule for OMB review under Executive Order 12866.
(1) The rule will not have an effect of $100 million or more on the
economy. It will not adversely affect in a material way the economy,
productivity, competition, jobs, the environment, public health or
safety, or State, local, or tribal governments or communities. The
major purpose of this rule is the restructuring of the rule and
simplifying the regulatory language. The restructuring and plain
language revisions will not result in any economic effects to small or
large entities. Some of the technical revisions will have a minor
economic effect on lessees and drilling contractors.
Specifically, given the existing industry structure (i.e., the
number and size of affected regulated entities remain constant), MMS
estimates the cost to implement the rule at $1 million annually.
In addition to the annual costs, the rule requires the installation
of blind-shear rams in surface BOP stacks that will result in a one-
time cost of $14,175,000. This rule allows a 3-year period for the
installation of the new rams. The most significant benefits of
preventing or minimizing some blowouts will be the reduced risk of
injury or fatality to personnel and of environmental damage. Property
damages (including lost productivity) resulting from blowouts will also
be reduced by this final rule. Property and financial damages from a
blowout or near blowout can range from minimal damage to a facility and
the loss of a day's activity to the total loss of the drilling rig and
production facility.
MMS believes that the installation of blind-shear rams in surface
BOP stacks could prevent or minimize approximately one blowout every 2
years. This estimate comes from the 5 incidents that MMS identified
where a blind-shear ram had helped or could have helped prevent or
minimize a blowout over the past 10-year period (1992 to present).
Considering that a single blowout could cause multiple fatalities,
injuries, and tens of millions of dollars in property damage and
financial losses, MMS believes that the benefits of this requirement
will more than offset the cost of this new requirement.
(2) This rule will not create a serious inconsistency or otherwise
interfere with an action taken or planned by another agency. The rule
does not affect how lessees or operators interact with other agencies.
Nor does this rule affect how MMS will interact with other agencies.
(3) This rule does not alter the budgetary effects or entitlements,
grants, user fees, or loan programs or the rights or obligations of
their recipients. The rule only addresses the regulatory requirements
for obtaining permission to drill on the OCS and the safety of drilling
operations.
(4) OMB has determined that this rule raises novel legal or policy
issues. The rule has some new policy issues, such as requiring minimum
BOP maintenance requirements. OMB has determined that these issues make
this rule a significant rule as defined in Executive Order 12866.
[[Page 8418]]
Regulatory Flexibility (RF) Act
The Department of the Interior (DOI) certifies that this rule will
not have a significant economic effect on a substantial number of small
entities under the RF Act (5 U.S.C. 601 et seq.). This rule applies to
all lessees and drilling contractors that operate on the OCS. Small
lessees and drilling contractors that operate under this final rule
would fall under the Small Business Administration's (SBA) North
American Industry Classification System codes 211111, Crude Petroleum
and Natural Gas Extraction, and 213111 Drilling Oil and Gas Wells.
Under these codes, SBA considers all companies with fewer than 500
employees to be a small business. Given the variability in the industry
due to changes in the relative prices of oil and natural gas, the
numbers of small entities affected by the rule may change over time.
Based on data from 1998, we estimate that of the 130 lessees that
explore for and produce oil and gas on the OCS, approximately 90 are
small businesses (70 percent). We also estimate that 10 drilling
contractors operate on the OCS, and none of those drilling contractors
are classified as a small business. The number of drilling contractors
is based on current drilling activity on the OCS, and the size of each
drilling contractor is based on research into company statistics.
Drilling requirement costs will be borne by the OCS lessees who
explore for and produce oil and are dependent on the number of wells
drilled. We estimate that the total annual cost of the new drilling
requirements in this rule to be approximately $670,000, as shown in the
following table. The table also shows the estimated cost per well for
the approximately 700 wells drilled annually on the OCS using a surface
BOP stack.
Estimated Costs of Additional Drilling Requirements
------------------------------------------------------------------------
Total cost
for 700
Cost Cost per wells
well drilled
annually
------------------------------------------------------------------------
One hour per well additional evaluation time on $100 $70,000
cementing operations @ $100....................
One hour per well additional drilling rig rental 850 $595,000
@ $850.........................................
Annual reporting and paperwork burden--140 hours 10 $7,000
@ $50..........................................
------------
Total....................................... 960 $672,000
------------------------------------------------------------------------
* The annual reporting and paperwork burden for the entire subpart D,
``Oil and Gas Drilling Operations'' is 111,209 hours as indicated in
the Paperwork Reduction Act of 1995 section of this preamble. However,
the new burden added when the this rule was proposed is only 140 hours
(Sec. 250.403-100 hours; Sec. 250.460(b)-30 hours; and Sec.
250.461(e)--10 hours).
As indicated in the table, the estimated cost per well is about
$1,000. Based on drilling data from 1999, we estimate that the 90 small
businesses that explore for and produce oil and gas on the OCS drill
about 300 of the 700 wells drilled annually on the OCS using a surface
BOP stack. Thus, with the small businesses drilling an average of 3\1/
3\ wells per year, the annual economic effect for each small business
is about $3,300, or about $300,000 in total. The estimated additional
cost of $1,000 per well is quite small (about .02 percent) when
compared to the $5 million average cost of drilling a well. Based on
this very low percentage of well cost, we believe that these revisions
to the regulations will not have a significant economic effect on any
small lessee.
The estimated economic effect of the requirement to use blind-shear
rams on surface BOP stacks is the cost to purchase the rams. This
requirement imposes no reporting or recordkeeping burden. This
requirement primarily will affect drilling contractors operating jackup
and platform rigs on the OCS who will be required to purchase the rams.
Using information from 2003, the cost for a set of 10,000 pounds per-
square-inch rams and associated equipment is about $105,000. Some sets
of rams for lower-rated BOP stacks will cost less, while a few sets of
rams will cost more for higher-rated BOP stacks, but the average cost
will remain at about $105,000.
In the proposed rule we estimated that drilling contractors would
need to purchase a total of 80 blind-shear rams to meet the proposed
requirements. We have revised that estimate to 135 sets of rams for
reasons as discussed in our response to comments. At an average cost of
about $105,000, the economic impact will be $14,175,000. The largest
drilling contractor may need to purchase up to 40 sets of blind-shear
rams, while one drilling contractor will not have to purchase any
blind-shear rams because it has already installed blind-shear rams in
all of its surface BOP stacks. When asked why, a company executive
responded that it was a prudent safety measure. A large contractor may
get a minor reduction in the cost with a bulk purchase, but this
reduction should not significantly affect the competition between large
and small contractors because the unit costs will not vary much.
Purchase of the rams to meet the proposed requirements will be an
initial one-time cost. A blind-shear ram should last for 20 years if
properly maintained.
The blind-shear ram requirement should not hinder the ability of
lessees or contractors, including small businesses, to conduct business
on the OCS. The final rule provides for a 3-year period after the
effective date for drilling contractors to plan and purchase the rams
and associated equipment. This will allow contractors sufficient time
to obtain the equipment.
The following table summarizes the estimated economic effects
associated with this final rule.
----------------------------------------------------------------------------------------------------------------
Cost to small
Requirement Frequency Total cost businesses
----------------------------------------------------------------------------------------------------------------
New drilling rules........................... Annual........................... $672,000 $300,000
Use of blind-shear rams...................... One-time......................... 14,175,000 0
-----------------
Total.................................... ................................. 14,847,000 300,000
----------------------------------------------------------------------------------------------------------------
[[Page 8419]]
We do not believe that this rule will have a significant impact on
the lessees and drilling contractors who explore for and produce oil
and gas on the OCS, including those that are classified as small
businesses.
Your comments are important. The Small Business and Agriculture
Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were
established to receive comments from small business about Federal
agency enforcement actions. The Ombudsman will annually evaluate the
enforcement activities and rate each agency's responsiveness to small
business. If you wish to comment on the actions of MMS, call 1-888-REG-
FAIR (1-888-734-3247). You may comment to the Small Business
Administration without fear of retaliation. Disciplinary action for
retaliation by an MMS employee may include suspension or termination
from employment with the Department of the Interior.
Small Business Regulatory Enforcement Fairness Act (SBREFA)
This rule is not a major rule under (5 U.S.C. 804(2)) the SBREFA.
The rule:
(1) Does not have an annual effect on the economy of $100 million
or more. As described above, we estimate that the annual cost of the
rule to be approximately $672,000. The cost for the blind-shear rams
will be $14,175,000, which will be spread over a 3-year period. This
cost will not cause an annual effect on the economy of $100 million.
(2) Will not cause a major increase in costs or prices for
consumers, individual industries, Federal, State, or local government
agencies, or geographic regions. The minor increase in drilling costs
will not change the way the oil and gas industry conducts business, nor
will it affect regional oil and gas prices; therefore, it will not
cause major cost increases for consumers, the oil and gas industry, or
any Government agencies.
(3) Does not have significant adverse effects on competition,
employment, investment, productivity, innovation, or ability of United
States-based enterprises to compete with foreign-based enterprises. All
lessees and drilling contractors, regardless of nationality, will have
to comply with the requirements of this rule. So the rule will not
affect competition, employment, investment, productivity, innovation,
or the ability of United States-based enterprises to compete with
foreign-based enterprises.
Paperwork Reduction Act (PRA) of 1995
We examined the proposed rule and these final regulations under
section 3507(d) of the PRA. The proposed rulemaking added only a few
new information collection requirements, which we submitted to OMB for
approval as part of the proposed rulemaking process. There have been
some changes to the numbering of sections requiring the collection of
information in the final regulations, as well as some clarifications.
However, the final regulations do not impose any additional information
collection paperwork burden.
MMS regulations in 30 CFR 250, subpart A, at Sec. Sec. 250.140,
250.141, and 250.142 allow respondents to request the use of
``alternative procedures or equipment'' and ``departures'' to operating
requirements. However, our information collection submission to OMB
(1010-0114) indicated that the burden for these requests is covered
under the applicable operating requirement. To account for these non-
specific possibilities, as MMS renews the various collections covering
subparts of the part 250 regulations and the other 30 CFR parts, as a
standard procedure we are now including these requests as a ``line
item'' in the regulation burden charts. Based on comments we received
on the proposed subpart D rulemaking, Sec. Sec. 250.408 and 250.409 of
these final regulations specifically address these issues and a line
item has been included in the burden chart for this collection. It
should be reiterated that these requests are not new information
collection requirements. However, this inclusion will ensure that the
burden is not overlooked for some operating requirements and will
provide for any oversight.
Because of the adjustments discussed in the preceding paragraphs
and section numbering changes, before publication, we again submitted
the final subpart D information collection to OMB and OMB approved them
under OMB control number 1010-0141, with a current expiration date of
January 28, 2003. An agency may not conduct or sponsor, and you are not
required to respond to, a collection of information unless it displays
a currently valid OMB control number.
The title of the collection of information for this final rule is
``30 CFR 250, Subpart D--Oil and Gas Drilling Operations.'' Respondents
include approximately 130 Federal OCS oil and gas or sulphur lessees.
The frequency of response varies, depending upon the requirement.
Responses are mandatory. MMS will protect proprietary information
according to the Freedom of Information Act and 30 CFR 250.196, ``Data
and information to be made available to the public.''
The final regulations convert into plain language and restructure
the requirements for oil and gas drilling operations. The approved
information collection for this final rule will supersede the
collection for current subpart D regulations (OMB control number 1010-
0053), which we will cancel when the new subpart D regulations take
effect.
We estimate the total annual paperwork ``hour'' burden for the
final rule to be 111,209 hours. Following is a breakdown of the hour
burden estimate.
[[Page 8420]]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual
Citation 30 CFR 250 Subpart D Reporting and recordkeeping requirement Hour Average number per year burden
burden hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
402(b)................................ Request approval to use blind or blind-shear ram .25 6 requests.............................. 2
or pipe rams and inside BOP.
403................................... Notify MMS of drilling rig movement on or off .1 20 notices.............................. 2
drilling location.
--------------------------------------------------------------------------------------------------------
In Gulf of Mexico OCS Region, rig movements reported on form MMS-144--burden covered under 1010-0150.
--------------------------------------------------------------------------------------------------------
408, 409.............................. Apply for use alternative procedures and/or 1 20% of 1,200 drilling ops. = 240........ 240
departures not requested in MMS forms (including
discussions with MMS and approvals.
--------------------------------------------------------------------------------------------------------
408, 409; 410-418, plus various other Apply for permit to drill and requests for various approvals required in subpart D (including Sec. 0
references in subpart D. Sec. 250.423, 424, 442(c), 451(g), 456(f)) and obtained via forms MMS-123 (Application for Permit
to Drill) and MMS-123S (Supplemental APD Information Sheet), and supporting information and notices
to MMS--burden covered under 1010-0044 and 1010-0131.
--------------------------------------------------------------------------------------------------------
410(a)(3), 417(b)..................... Reference to Exploration Plan, Development and Production Plan, Development Operations Coordination 0
Document (30 CFR 250, subpart B)--burden covered under 1010-0049.
--------------------------------------------------------------------------------------------------------
417(a), (b)........................... Collect and report additional information on case- 4 1 report................................ 4
by-case basis if sufficient information is not
available.
--------------------------------------------------------------------------------------------------------
417(c)................................ Submit 3rd party review of drilling unit according to 30 CFR 250, subpart I--burden covered under 0
1010-0058.
--------------------------------------------------------------------------------------------------------
418(e)................................ Submit welding and burning plan according to 30 CFR 250, subpart A--burden covered under 1010-0114 0
--------------------------------------------------------------------------------------------------------
421; 423; 428......................... Submit casing and cementing program and revisions 2 20% of 1,200 drilling ops. = 240........ 480
or changes.
424................................... Caliper, pressure test, or evaluate casing; submit 5 20% of 1,200 wells = 240................ 1,200
evaluation results; request approval before
resuming operations or beginning repairs (every
30 days during prolonged drilling).
456(c), (f)........................... Perform various calculations; post information (on .25 144 drilling rigs x 52 =7,488........... 1,872
occasion, daily, weekly).
459(a)(3)............................. Request exception to procedure for protecting 2 5 requests.............................. 10
negative pressure area.
--------------------------------------------------------------------------------------------------------
460; 465.............................. Submit revised plans, changes, well/drilling records, etc., on forms MMS-124 (Application for Permit 0
to Modify) or MMS-125 (End of Operations Report)--burden covered under 1010-0045 and 1010-0046
--------------------------------------------------------------------------------------------------------
460................................... Submit plans for well testing and notify MMS 2 15 plans................................ 30
before test.
461(e)................................ Provide copy of well directional survey to 1 10 occasions............................ 10
affected leaseholder.
462(a)................................ Prepare and post well control drill plan for crew 3 26 plans................................ 78
members.
463(b)................................ Request field drilling rules be established, 2.5 6 requests.............................. 15
amended, or canceled.
468(a)................................ Submit well logs.................................. 1.5 1,200 logs/surveys...................... 1,800
Submit directional and vertical-well surveys...... .5 1,200 reports........................... 600
Submit velocity profiles and surveys.............. .25 55 reports.............................. 14
Submit core analyses.............................. .25 150 analyses............................ 38
--------------------------------------------------------------------------------------------------------
468(b); 465(b)(3)..................... In the GOM OCS Region, submit drilling activity reports on form MMS-133 (Well Activity Report)-- 0
burden covered under 1010-0132
--------------------------------------------------------------------------------------------------------
468(c)................................ In the Pacific and Alaska OCS Regions during 1 14 wells x 365 days x 20% = 1,022....... 1,022
drilling operations, submit daily drilling
reports.
469................................... As specified by region, submit well records, .25 300 submissions......................... 75
paleontological interpretations or reports,
service company reports, and other reports or
records of operations.
490(c)(4), (d)........................ Submit request for reclassification of H2S zone; 1.7 27 responses............................ 46
notify MMS if conditions change.
490(f); also referred to in 418(d).... Submit contingency plans for operations in H2S 10 27 plans................................ 270
areas (16 drilling, 5 work-over, 6 production).
--------------------------------------------------------------------------------------------------------
490(i)................................ Display warning signs--no burden as facilities would display warning signs and use other visual and 0
audible systems.
490(j)(12)............................ Propose alternatives to minimize or eliminate SO2 hazards--submitted with contingency plans--burden 0
covered under 250.490(f).
490(j)(13)(vi)........................ Label breathing air bottles--no burden as supplier normally labels bottles; facilities would 0
routinely label if not.
--------------------------------------------------------------------------------------------------------
490(l)................................ Notify (phone) MMS of unplanned H2S releases .2 49 facilities x 2 = 98.................. 20
(approx. 2/year).
490(o)(5)............................. Request approval to use drill pipe for well 2 3 requests.............................. 6
testing.
--------------------------------------------------------------------------------------------------------
[[Page 8421]]
490(q)(1)............................. Seal and mark for the presence of H2S cores to be transported--no burden as facilities would 0
routinely mark transported cores.
--------------------------------------------------------------------------------------------------------
490(q)(9)............................. Request approval to use gas containing H2S for 2 3 requests.............................. 6
instrument gas.
490(q)(12)............................ Analyze produced water disposed of for H2S content 2.8 4 production platforms x 52 = 208....... 582
and submit results to MMS on occasion (approx.
weekly).
-----------
Reporting Subtotal................ .................................................. ........ 12,590 Responses........................ 8,422
-----------
404................................... Perform operational check of crown block safety .1 144 drilling rigs x 52 = 7,488.......... 749
device; record results (weekly).
426................................... Perform pressure test on all casing strings and 2 144 drilling rigs x approx. 50 per rig = 14,400
drilling liner lap; record results. 7,200.
427(a)................................ Perform pressure-integrity tests and related hole- 4 425 tests............................... 1,700
behavior observations; record results.
434; 467.............................. Perform diverter tests when installed and once 2 1,200 drilling ops. x 2 = 2,400......... 4,800
every 7 days; actuate system at least once every
24-hour period; record results (average 2 per
drilling operation).
450; 467.............................. Perform BOP pressure tests, actuations and 6 144 drilling rigs x approx. 35 per rig = 30,240
inspections when installed; at a minimum every 14 5,040.
days; as stated for components; record results.
450, 467.............................. Function test annulars and rams; document results .16 144 drilling rigs x approx. 20 per rig = 461
every 7 days between BOP tests (biweekly). Note: 2,880.
this test is part of BOP test when BOP test is
conducted.
451(c)................................ Record reason for postponing BOP test (on .1 144 drilling rigs x 2 = 288............. 29
occasion--approx. 2/year).
456(b), (i); 458(b)................... Record each drilling fluid circulation; test 1.25 144 drilling rigs x 52 = 7,488.......... 9,360
drilling fluid, record results; record daily
inventory of drilling fluid/materials; test and
recalibrate gas detectors; record results (on
occasion, daily, weekly, quarterly).
462(c)................................ Perform well-control drills; record results (2 1 144 drilling rigs x 2 crews x 52 = 14,976
crews weekly). 14,976.
466, 467.............................. Retain drilling records for 90 days after drilling 1.5 Annual records maintenance for 1,200 1,800
is complete; retain casing/liner pressure, wells.
diverter, and BOP for 2 years; retain well
completion/well workover until well is
permanently plugged/abandoned or lease assigned.
490(g)(2), (g)(5)..................... Conduct H2S training; post safety instructions; 2 49 facilities x 2 = 98.................. 196
document training on occasion and annual
refresher (approx. 2/year).
490(h)(2)............................. Conduct weekly drills and safety meetings; 1 49 facilities x 52 = 2,548.............. 2,548
document attendance.
490(j)(8)............................. Test H2S detection and monitoring sensors during 2 26 drilling rigs x 365 days = 9,490..... 18,980
drilling; record testing and calibrations on
occasion, daily during drilling (approx. 12
sensors per rig).
490(j)(8)............................. Test H2S detection and monitoring sensors every 14 3.5 28 production platforms x 26 = 728...... 2,548
days during production; record testing and
calibrations (approx. 30 sensors/5 platforms +
approx. 42 sensors/23 platforms).
=====================================================
--------------------------------------------------------------------------------------------------------------------------------------------------------
Federalism (Executive Order 13132)
According to Executive Order 13132, this rule does not have
Federalism implications. This rule does not substantially and directly
affect the relationship between the Federal and State Governments. The
rule applies to lessees and drilling contractors that operate on the
OCS. This rule does not impose costs on States or localities. Any costs
will be the responsibility of the lessees and drilling contractors.
Takings Implication Assessment (Executive Order 12630)
According to Executive Order 12630, the rule does not have
significant Takings Implications. A Takings Implication Assessment is
not required. The rule revises existing operation regulations. It does
not prevent any lessee, operator, or drilling contractor from
performing operations on the OCS, provided they follow the regulations.
Thus, MMS did not need to prepare a Takings Implication Assessment
under Executive Order 12630, Governmental Actions and Interference with
Constitutionally Protected Property Rights.
Energy Supply, Distribution, or Use (Executive Order 13211)
Although OMB has designated this a significant rule under Executive
Order 12866, it does not have a significant effect on energy supply,
distribution, or use. The rule essentially clarifies the current
regulatory requirements for oil and gas drilling on the OCS. The rule
also adds a new requirement (blind-shear rams in surface BOP stacks)
that will result in a one-time cost to the industry of $14,175,000.
However, the
[[Page 8422]]
increased safety aspects associated with the new requirement along with
the potential for reduced property damages and financial losses will
offset the $14,175,000 cost of the new rams. Accordingly the new
requirement will not cause a reduction in crude oil supply or an
increase in energy prices.
Civil Justice Reform (Executive Order 12988)
According to Executive Order 12988, the Office of the Solicitor has
determined that this rule does not unduly burden the judicial system
and does meet the requirements of sections 3(a) and 3(b)(2) of the
Order.
National Environmental Policy Act (NEPA)
This rule does not constitute a major Federal action significantly
affecting the quality of the human environment. An environmental
assessment is not required.
Unfunded Mandates Reform Act (UMRA) of 1995 (Executive Order 12866)
This rule does not impose an unfunded mandate on State, local, or
tribal governments or the private sector of more than $100 million per
year. The rule does not have any Federal mandates, nor does the rule
have a significant or unique effect on State, local, or tribal
governments or the private sector. A statement containing the
information required by the UMRA (2 U.S.C. 1531 et seq.) is not
required.
List of Subjects in 30 CFR Part 250
Continental shelf, Environmental impact statements, Environmental
protection, Government contracts, Incorporation by reference,
Investigations, Mineral royalties, Oil and gas development and
production, Oil and gas exploration, Oil and gas reserves, Penalties,
Pipelines, Public lands-mineral resources, Public lands-rights-of-way,
Reporting and recordkeeping requirements, Sulphur development and
production, Sulphur exploration, Surety bonds.
Dated: October 24, 2002.
Rebecca W. Watson,
Assistant Secretary, Land and Minerals Management.
For the reasons stated in the preamble, the Minerals Management
Service (MMS) amends 30 CFR Part 250 as follows:
PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER
CONTINENTAL SHELF
1. The authority citation for part 250 continues to read as
follows:
Authority: 43 U.S.C. 1331 et seq.
2. In Sec. 250.102, in the table in paragraph (b), paragraph (1)
is revised to read as follows:
----------------------------------------------------------------------------------------------------------------
For information about Refer to
----------------------------------------------------------------------------------------------------------------
(1) Applications for permit to drill............. Sec. 250.410
* * * * * *
----------------------------------------------------------------------------------------------------------------
3. In Sec. 250.105, in the definition for Facility (3), the
citation ``Sec. 250.417(b)'' is revised to read ``Sec. 250.490(b)''.
4. In Sec. 250.198, in the table in paragraph (e), the following
changes are made in alphanumeric order:
A. Add an entry for API RP 53 as set forth below.
B. Revise the entries for ANSI Z88.2-1992, API RP 500, API RP 505,
and NACE Standard MR0175-99 as set forth below.
250.198 Documents incorporated by reference.
* * * * *
(e) * * *
----------------------------------------------------------------------------------------------------------------
Title of documents Incorporated by reference at
----------------------------------------------------------------------------------------------------------------
* * * * * * *
ANSI Z88.2-1992, American National Standard for Sec. 250.490(g)(4)(iv), (j)(13)(ii).
Respiratory Protection.
* * * * * * *
API RP 53, Recommended Practices for Blowout Sec. 250.442(c); Sec. 250.446(a).
Prevention Equipment Systems for Drilling Wells,
Third Edition, March 1997, API Stock No. G53003.
API RP 500, Recommended Practice for Sec. 250.114(a); Sec. 250.459; Sec. 250.802(e)(4)(i);
Classification of Locations for Electrical Sec. 250.803(b)(9)(i); Sec. 250.1628(b)(3); (d)(4)(i);
Installations at Petroleum Facilities, Sec. 250.1629(b)(4)(i).
Classified as Class I, Division 1 and Division
2, Second Edition, November 1997, API Stock No.
C50002.
API RP 505, Recommended Practice for Sec. 250.114(a); Sec. 250.459; Sec. 250.802(e)(4)(i);
Classification of Locations for Electrical Sec. 250.803(b)(9)(i); Sec. 250.1628(b)(3); (d)(4)(i);
Installations at Petroleum Facilities, Sec. 250.1629(b)(4)(i).
Classified as Class I, Zone 0, Zone 1, and Zone
2, First Edition, November 1997, API Stock No.
C50501.
* * * * * * *
NACE Standard MR0175-99, Sulfide Stress Cracking Sec. 250.490(p)(2).
Resistant Metallic Materials for Oilfield
Equipment, Revised January 1999, NACE Item No.
21302.
* * * * * * *
----------------------------------------------------------------------------------------------------------------
5. In Sec. 250.199, in the table in paragraph (e), the OMB control
number ``1010-0053'' cited in the entry for item (4) is revised to read
``1010-0141''.
6. In Sec. 250.203, the following changes are made:
A. In paragraphs (b)(5)(i) and (b)(5)(ii), the citation ``250.417''
is revised to read ``250.490''.
B. In paragraph (p), the citation ``Sec. 250.414'' is revised to
read ``Sec. 250.410 throughSec. 250.418''.
7. In Sec. 250.204, the following changes are made:
A. In paragraphs (b)(2)(i) and (b)(2)(ii), the citation ``Sec.
250.417'' is revised to read Sec. 250.490''.
[[Page 8423]]
B. In paragraph (t), the citation ``Sec. 250.414'' is revised to
read ``Sec. 250.410 through Sec. 250.418''.
8. In 30 CFR part 250, subpart D, Sec. 250.417 is redesignated as
Sec. 250.490, Sec. Sec. 250.400 through 250.416 are revised, and
Sec. Sec. 250.417 through 250.469 are added, and a new undesignated
center heading is added preceding redesignated Sec. Sec. 250.490 to
read as set forth below. For the convenience of the reader, the table
of contents for subpart D is also set forth below:
Subpart D--Oil and Gas Drilling Operations
General Requirements
Sec.
250.400 Who is subject to the requirements of this subpart?
250.401 What must I do to keep wells under control?
250.402 When and how must I secure a well?
250.403 What drilling unit movements must I report?
250.404 What are the requirements for the crown block?
250.405 What are the safety requirements for diesel engines used on
a drilling rig?
250.406 What additional safety measures must I take when I conduct
drilling operations on a platform that has producing wells or has
other hydrocarbon flow?
250.407 What tests must I conduct to determine reservoir
characteristics?
250.408 May I use alternative procedures or equipment during
drilling operations?
250.409 May I obtain departures from these drilling requirements?
Applying for a Permit To Drill
250.410 How do I obtain approval to drill a well?
250.411 What information must I submit with my application?
250.412 What requirements must the location plat meet?
250.413 What must my description of well drilling design criteria
address?
250.414 What must my drilling prognosis include?
250.415 What must my casing and cementing programs include?
250.416 What must I include in the diverter and BOP descriptions?
250.417 What must I provide if I plan to use a mobile offshore
drilling unit (MODU)?
250.418 What additional information must I submit with my APD?
Casing and Cementing Requirements
250.420 What well casing and cementing requirements must I meet?
250.421 What are the casing and cementing requirements by type of
casing string?
250.422 When may I resume drilling after cementing?
250.423 What are the requirements for pressure testing casing?
250.424 What are the requirements for prolonged drilling operations?
250.425 What are the requirements for pressure testing liners?
250.426 What are the recordkeeping requirements for casing and liner
pressure tests?
250.427 What are the requirements for pressure integrity tests?
250.428 What must I do in certain cementing and casing situations?
Diverter System Requirements
250.430 When must I install a diverter system?
250.431 What are the diverter design and installation requirements?
250.432 How do I obtain a departure to diverter design and
installation requirements?
250.433 What are the diverter actuation and testing requirements?
250.434 What are the recordkeeping requirements for diverter
actuations and tests?
Blowout Preventer (BOP) System Requirements
250.440 What are the general requirements for BOP systems and system
components?
250.441 What are the requirements for a surface BOP stack?
250.442 What are the requirements for a subsea BOP stack?
250.443 What associated systems and related equipment must all BOP
systems include?
250.444 What are the choke manifold requirements?
250.445 What are the requirements for kelly valves, inside BOPs, and
drill-string safety valves?
250.446 What are the BOP maintenance and inspection requirements?
250.447 When must I pressure test the BOP system?
250.448 What are the BOP pressure tests requirements?
250.449 What additional BOP testing requirements must I meet?
250.450 What are the recordkeeping requirements for BOP tests?
250.451 What must I do in certain situations involving BOP equipment
or systems?
Drilling Fluid Requirements
250.455 What are the general requirements for a drilling fluid
program?
250.456 What safe practices must the drilling fluid program follow?
250.457 What equipment is required to monitor drilling fluids?
250.458 What quantities of drilling fluids are required?
250.459 What are the safety requirements for drilling fluid-handling
areas?
Other Drilling Requirements
250.460 What are the requirements for conducting a well test?
250.461 What are the requirements for directional and inclination
surveys?
250.462 What are the requirements for well-control drills?
250.463 Who establishes field drilling rules?
Applying for a Permit To Modify and Well Records
250.465 When must I submit an Application for Permit to Modify (AMP)
or an End of Operations Report to MMS?
250.466 What records must I keep?
250.467 How long must I keep records?
250.468 What well records am I required to submit?
250.469 What other well records could I be required to submit?
Hydrogen Sulfide
250.490 Hydrogen sulfide.
Subpart D--Oil and Gas Drilling Operations
General Requirements
Sec. 250.400 Who is subject to the requirements of this subpart?
The requirements of this subpart apply to lessees, operating rights
owners, operators, and their contractors and subcontractors.
Sec. 250.401 What must I do to keep wells under control?
You must take necessary precautions to keep wells under control at
all times. You must:
(a) Use the best available and safest drilling technology to
monitor and evaluate well conditions and to minimize the potential for
the well to flow or kick;
(b) Have a person onsite during drilling operations who represents
your interests and can fulfill your responsibilities;
(c) Ensure that the toolpusher, operator's representative, or a
member of the drilling crew maintains continuous surveillance on the
rig floor from the beginning of drilling operations until the well is
completed or abandoned, unless you have secured the well with blowout
preventers (BOPs), bridge plugs, cement plugs, or packers;
(d) Use personnel trained according to the provisions of subpart O;
and
(e) Use and maintain equipment and materials necessary to ensure
the safety and protection of personnel, equipment, natural resources,
and the environment.
Sec. 250.402 When and how must I secure a well?
Whenever you interrupt drilling operations, you must install a
downhole safety device, such as a cement plug, bridge plug, or packer.
You must install the device at an appropriate depth within a properly
cemented casing string or liner.
(a) Among the events that may cause you to interrupt drilling
operations are:
(1) Evacuation of the drilling crew;
(2) Inability to keep the drilling rig on location; or
[[Page 8424]]
(3) Repair to major drilling or well-control equipment.
(b) For floating drilling operations, the District Supervisor may
approve the use of blind or blind-shear rams or pipe rams and an inside
BOP if you don't have time to install a downhole safety device or if
special circumstances occur.
Sec. 250.403 What drilling unit movements must I report?
(a) You must report the movement of all drilling units on and off
drilling locations to the District Supervisor. This includes both MODU
and platform rigs. You must inform the District Supervisor 24 hours
before:
(1) The arrival of an MODU on location;
(2) The movement of a platform rig to a platform;
(3) The movement of a platform rig to another slot;
(4) The movement of an MODU to another slot; and
(5) The departure of an MODU from the location.
(b) You must provide the District Supervisor with the rig name,
lease number, well number, and expected time of arrival or departure.
(c) In the Gulf of Mexico OCS Region, you must report drilling unit
movements on form MMS-144, Rig Movement Notification Report.
Sec. 250.404 What are the requirements for the crown block?
You must have a crown block safety device that prevents the
traveling block from striking the crown block. You must check the
device for proper operation at least once per week and after each
drill-line slipping operation and record the results of this
operational check in the driller's report.
Sec. 250.405 What are the safety requirements for diesel engines used
on a drilling rig?
You must equip each diesel engine with an air take device to shut
down the diesel engine in the event of a runaway.
(a) For a diesel engine that is not continuously manned, you must
equip the engine with an automatic shutdown device;
(b) For a diesel engine that is continuously manned, you may equip
the engine with either an automatic or remote manual air intake
shutdown device;
(c) You do not have to equip a diesel engine with an air intake
device if it meets one of the following criteria:
(1) Starts a larger engine;
(2) Powers a firewater pump;
(3) Powers an emergency generator;
(4) Powers a BOP accumulator system;
(5) Provides air supply to divers or confined entry personnel;
(6) Powers temporary equipment on a nonproducing platform;
(7) Powers an escape capsule; or
(8) Powers a portable single-cylinder rig washer.
Sec. 250.406 What additional safety measures must I take when I
conduct drilling operations on a platform that has producing wells or
has other hydrocarbon flow?
You must take the following safety measures when you conduct
drilling operations on a platform with producing wells or that has
other hydrocarbon flow:
(a) You must install an emergency shutdown station near the
driller's console;
(b) You must shut in all producible wells located in the affected
wellbay below the surface and at the wellhead when:
(1) You move a drilling rig or related equipment on and off a
platform. This includes rigging up and rigging down activities within
500 feet of the affected platform;
(2) You move or skid a drilling unit between wells on a platform;
(3) A mobile offshore drilling unit (MODU) moves within 500 feet of
a platform. You may resume production once the MODU is in place,
secured, and ready to begin drilling operations.
Sec. 250.407 What tests must I conduct to determine reservoir
characteristics?
You must determine the presence, quantity, quality, and reservoir
characteristics of oil, gas, sulphur, and water in the formations
penetrated by logging, formation sampling, or well testing.
Sec. 250.408 May I use alternative procedures or equipment during
drilling operations?
You may use alternative procedures or equipment during drilling
operations after receiving approval from the District Supervisor. You
must identify and discuss your proposed alternative procedures or
equipment in your Application for Permit to Drill (APD) (see Sec.
250.414(h)). Procedures for obtaining approval are described in section
250.141 of this part.
Sec. 250.409 May I obtain departures from these drilling
requirements?
The District Supervisor may approve departures from the drilling
requirements specified in this subpart. You may apply for a departure
from drilling requirements by writing to the District Supervisor. You
should identify and discuss the departure you are requesting in your
APD (see Sec. 250.414(h)).
Applying for a Permit To Drill
Sec. 250.410 How do I obtain approval to drill a well?
You must obtain written approval from the District Supervisor
before you begin drilling any well or before you sidetrack, bypass, or
deepen a well. To obtain approval, you must:
(a) Submit the information required by Sec. 250.411 through
250.418;
(b) Include the well in your approved Exploration Plan (EP),
Development and Production Plan (DPP), or Development Operations
Coordination Document (DOCD);
(c) Meet the oil spill financial responsibility requirements for
offshore facilities as required by 30 CFR part 253; and
(d) Submit the following forms to the District Supervisor:
(1) An original and two complete copies of form MMS-123,
Application for a Permit to Drill (APD), and form MMS-123S,
Supplemental APD Information Sheet; and
(2) A separate public information copy of forms MMS-123 and MMS-
123S that meets the requirements of Sec. 250.127.
Sec. 250.411 What information must I submit with my application?
In addition to forms MMS-123 and MMS-123S, you must include the
information described in the following table.
------------------------------------------------------------------------
Information that you must include with an
APD Where to find a description
------------------------------------------------------------------------
(a) Plat that shows locations of the Sec. 250.412
proposed well.
(b) Design criteria used for the proposed Sec. 250.413
well.
(c) Drilling prognosis.................... Sec. 250.414
(d) Casing and cementing programs......... Sec. 250.415
(e) Diverter and BOP systems descriptions. Sec. 250.416
(f) Requirements for using an MODU........ Sec. 250.417
[[Page 8425]]
(g) Additional information................ Sec. 250.418
------------------------------------------------------------------------
Sec. 250.412 What requirements must the location plat meet?
The location plat must:
(a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
(b) Show the surface and subsurface locations of the proposed well
and all the wells in the vicinity;
(c) Show the surface and subsurface locations of the proposed well
in feet or meters from the block line;
(d) Contain the longitude and latitude coordinates, and either
Universal Transverse Mercator grid-system coordinates or state plane
coordinates in the Lambert or Transverse Mercator Projection system for
the surface and subsurface locations of the proposed well; and
(e) State the units and geodetic datum (including whether the datum
is North American Datum 27 or 83) for these coordinates. If the datum
was converted, you must state the method used for this conversion,
since the various methods may produce different values.
Sec. 250.413 What must my description of well drilling design
criteria address?
Your description of well drilling design criteria must address:
(a) Pore pressures;
(b) Formation fracture gradients, adjusted for water depth;
(c) Potential lost circulation zones;
(d) Drilling fluid weights;
(e) Casing setting depths;
(f) Maximum anticipated surface pressures. For this section,
maximum anticipated surface pressures are the pressures that you
reasonably expect to be exerted upon a casing string and its related
wellhead equipment. In calculating maximum anticipated surface
pressures, you must consider: drilling, completion, and producing
conditions; drilling fluid densities to be used below various casing
strings; fracture gradients of the exposed formations; casing setting
depths; total well depth; formation fluid types; safety margins; and
other pertinent conditions. You must include the calculations used to
determine the pressures for the drilling and the completion phases,
including the anticipated surface pressure used for designing the
production string;
(g) A single plot containing estimated pore pressures, formation
fracture gradients, proposed drilling fluid weights, and casing setting
depths in true vertical measurements;
(h) A summary report of the shallow hazards site survey that
describes the geological and manmade conditions if not previously
submitted; and
(i) Permafrost zones, if applicable.
Sec. 250.414 What must my drilling prognosis include?
Your drilling prognosis must include a brief description of the
procedures you will follow in drilling the well. This prognosis
includes but is not limited to the following:
(a) Projected plans for coring at specified depths;
(b) Projected plans for logging;
(c) Planned safe drilling margin between proposed drilling fluid
weights and estimated pore pressures. This safe drilling margin may be
shown on the plot required by Sec. 250.413(g);
(d) Estimated depths to the top of significant marker formations;
(e) Estimated depths to significant porous and permeable zones
containing fresh water, oil, gas, or abnormally pressured formation
fluids;
(f) Estimated depths to major faults;
(g) Estimated depths of permafrost, if applicable;
(h) A list and description of all requests for using alternative
procedures or departures from the requirements of this subpart in one
place in the APD. You must explain how the alternative procedures
afford an equal or greater degree of protection, safety, or
performance, or why you need the departures; and
(i) Projected plans for well testing (refer to Sec. 250.460 for
safety requirements).
Sec. 250.415 What must my casing and cementing programs include?
Your casing and cementing programs must include:
(a) Hole sizes and casing sizes, including: weights; grades;
collapse, and burst values; types of connection; and setting depths
(measured and true vertical depth (TVD));
(b) Casing design safety factors for tension, collapse, and burst
with the assumptions made to arrive at these values;
(c) Type and amount of cement (in cubic feet) planned for each
casing string; and
(d) In areas containing permafrost, setting depths for conductor
and surface casing based on the anticipated depth of the permafrost.
Your program must provide protection from thaw subsidence and
freezeback effect, proper anchorage, and well control.
Sec. 250.416 What must I include in the diverter and BOP
descriptions?
You must include in the diverter and BOP descriptions:
(a) A description of the diverter system and its operating
procedures;
(b) A schematic drawing of the diverter system (plan and elevation
views) that shows: (1) the size of the annular BOP installed in the
diverter housing;
(2) spool outlet internal diameter(s);
(3) diverter-line lengths and diameters; burst strengths and radius
of curvature at each turn; and
(4) valve type, size, working pressure rating, and location;
(c) A description of the BOP system and system components,
including pressure ratings of BOP equipment and proposed BOP test
pressures;
(d) A schematic drawing of the BOP system that shows the inside
diameter of the BOP stack, number and type of preventers, location of
choke and kill lines, and associated valves; and
(e) Information that shows the blind-shear rams installed in the
BOP stack (both surface and subsea stacks) are capable of shearing the
drill pipe in the hole under maximum anticipated surface pressures.
Sec. 250.417 What must I provide if I plan to use a mobile offshore
drilling unit (MODU)?
If you plan to use a MODU, you must provide:
(a) Fitness requirements. You must provide information and data to
demonstrate the drilling unit's capability to perform at the proposed
drilling location. This information must include the maximum
environmental and operational conditions that the unit is designed to
withstand, including the minimum air gap necessary for both hurricane
and non-hurricane seasons. If sufficient environmental information and
data are not available at the time you submit your APD, the District
Supervisor may approve your APD but require you to collect and report
this information during operations. Under this circumstance, the
District Supervisor has the right to revoke the approval of the APD if
information collected during operations show that the drilling unit is
not capable of performing at the proposed location.
[[Page 8426]]
(b) Foundation requirements. You must provide information to show
that site-specific soil and oceanographic conditions are capable of
supporting the proposed drilling unit. If you provided sufficient site-
specific information in your EP, DPP, or DOCD, you may reference that
information. The District Supervisor may require you to conduct
additional surveys and soil borings before approving the APD if
additional information is needed to make a determination that the
conditions are capable of supporting the drilling unit.
(c) Frontier areas. (1) If the design of the drilling unit you plan
to use in a frontier area is unique or has not been proven for use in
the proposed environment, the District Supervisor may require you to
submit a third-party review of the unit's design. If required, you must
obtain the third-party review according to Sec. 250.903. You may
submit this information before submitting an APD.
(2) If you plan to drill in a frontier area, you must have a
contingency plan that addresses design and operating limitations of the
drilling unit. Your plan must identify the actions necessary to
maintain safety and prevent damage to the environment. Actions must
include the suspension, curtailment, or modification of drilling or rig
operations to remedy various operational or environmental situations
(e.g. vessel motion, riser offset, anchor tensions, wind speed, wave
height, currents, icing or ice-loading, settling, tilt or lateral
movement, resupply capability).
(d) U.S. Coast Guard (USCG) Documentation. You must provide the
current Certificate of Inspection or Letter of Compliance from the
USCG. You must also provide current documentation of any operational
limitations imposed by an appropriate classification society.
(e) Floating drilling unit. If you use a floating drilling unit,
you must indicate that you have a contingency plan for moving off
location in an emergency situation.
(f) Inspection of unit. The drilling unit must be available for
inspection by the District Supervisor before commencing operations.
(g) Once the District Supervisor has approved a MODU for use, you
do not need to re-submit the information required by this section for
another APD to use the same MODU unless changes in equipment affect its
rated capacity to operate in the District.
Sec. 250.418 What additional information must I submit with my APD?
You must include the following with the APD:
(a) Rated capacities of the drilling rig and major drilling
equipment, if not already on file with the appropriate District office;
(b) A drilling fluids program that includes the minimum quantities
of drilling fluids and drilling fluid materials, including weight
materials, to be kept at the site;
(c) A proposed directional plot if the well is to be directionally
drilled;
(d) A Hydrogen Sulfide Contingency Plan (see Sec. 250.490), if
applicable, and not previously submitted;
(e) A welding plan (see Sec. Sec. 250.109 to 250.113) if not
previously submitted;
(f) In areas subject to subfreezing conditions, evidence that the
drilling equipment, BOP systems and components, diverter systems, and
other associated equipment and materials are suitable for operating
under such conditions;
(g) A request for approval if you plan to wash out or displace some
cement to facilitate casing removal upon well abandonment; and
(h) Such other information as the District Supervisor may require.
Casing and Cementing Requirements
Sec. 250.420 What well casing and cementing requirements must I meet?
You must case and cement all wells. Your casing and cementing
programs must meet the requirements of this section and of Sec. Sec.
250.421 through 250.428.
(a) Casing and cementing program requirements. Your casing and
cementing programs must:
(1) Properly control formation pressures and fluids;
(2) Prevent the direct or indirect release of fluids from any
stratum through the wellbore into offshore waters;
(3) Prevent communication between separate hydrocarbon-bearing
strata;
(4) Protect freshwater aquifers from contamination; and
(5) Support unconsolidated sediments.
(b) Casing requirements. (1) You must design casing (including
liners) to withstand the anticipated stresses imposed by tensile,
compressive, and buckling loads; burst and collapse pressures; thermal
effects; and combinations thereof.
(2) The casing design must include safety measures that ensure well
control during drilling and safe operations during the life of the
well.
(c) Cementing requirements. You must design and conduct your
cementing jobs so that cement composition, placement techniques, and
waiting times ensure that the cement placed behind the bottom 500 feet
of casing attains a minimum compressive strength of 500 psi before
drilling out of the casing or before commencing completion operations.
Sec. 250.421 What are the casing and cementing requirements by type
of casing string?
The table in this section identifies specific design, setting, and
cementing requirements for casing strings and liners. For the purposes
of subpart D, the casing strings in order of normal installation are as
follows: drive or structural, conductor, surface, intermediate, and
production casings (including liners). The District Supervisor may
approve or prescribe other casing and cementing requirements where
appropriate.
----------------------------------------------------------------------------------------------------------------
Casing type Casing requirements Cementing requirements
----------------------------------------------------------------------------------------------------------------
(a) Drive or Structural......................... Set by driving, jetting, or If you drilled a portion of
drilling to the minimum depth this hole, you must use
as approved or prescribed by enough cement to fill the
the District Supervisor. annular space back to the
mudline.
(b) Conductor................................... Design casing and select Use enough cement to fill the
setting depths based on calculated annular space back
relevant engineering and to the mudline.
geologic factors. These Verify annular fill by
factors include the presence observing cement returns. If
or absence of hydrocarbons, you cannot observe cement
potential hazards, and water returns, use additional
depths. cement to ensure fill-back to
Set casing immediately before the mudline.
drilling into formations For drilling on an artificial
known to contain oil or gas. island or when using a glory
If you encounter oil or gas hole, you must discuss the
or unexpected formation cement fill level with the
pressure before the planned District Supervisor.
casing point, you must set
casing immediately.
[[Page 8427]]
(c) Surface..................................... Design casing and select Use enough cement to fill the
setting depths based on calculated annular space to
relevant engineering and at least 200 feet inside the
geologic factors. These conductor casing.
factors include the presence When geologic conditions such
or absence of hydrocarbons, as near-surface fractures and
potential hazards, and water faulting exist, you must use
depths. enough cement to fill the
calculated annular space to
the mudline.
(d) Intermediate................................ Design casing and select Use enough cement to cover and
setting depth based on isolate all hydrocarbon-
anticipated or encountered bearing zones and isolate
geologic characteristics or abnormal pressure intervals
wellbore conditions. from normal pressure
intervals in the well.
As a minimum, you must cement
the annular space 500 feet
above the casing shoe and 500
feet above each zone to be
isolated.
(e) Production.................................. Design casing and select Use enough cement to cover or
setting depth based on isolate all hydrocarbon-
anticipated or encountered bearing zones above the shoe.
geologic characteristics or As a minimum, you must cement
wellbore conditions. the annular space at least
500 feet above the casing
shoe and 500 feet above the
uppermost hydrocarbon-bearing
zone.
(f) Liners...................................... If you use a liner as Same as cementing requirements
conductor or surface casing, for specific casing types.
you must set the top of the For example, a liner used as
liner at least 200 feet above intermediate casing must be
the previous casing/liner cemented according to the
shoe. cementing requirements for
If you use a liner as an intermediate casing.
intermediate string below a
surface string or production
casing below an intermediate
string, you must set the top
of the liner at least 100
feet above the previous
casing shoe..
----------------------------------------------------------------------------------------------------------------
Sec. 250.422 When may I resume drilling after cementing?
(a) After cementing surface, intermediate, or production casing (or
liners), you may resume drilling after the cement has been held under
pressure for 12 hours. For conductor casing, you may resume drilling
after the cement has been held under pressure for 8 hours. One
acceptable method of holding cement under pressure is to use float
valves to hold the cement in place.
(b) If you plan to nipple down your diverter or BOP stack during
the 8- or 12-hour waiting time, you must determine, before nippling
down, when it will be safe to do so. You must base your determination
on a knowledge of formation conditions, cement composition, effects of
nippling down, presence of potential drilling hazards, well conditions
during drilling, cementing, and post cementing, as well as past
experience.
Sec. 250.423 What are the requirements for pressure testing casing?
The table in this section describes the minimum test pressures for
each string of casing. You may not resume drilling or other down-hole
operations until you obtain a satisfactory pressure test. If the
pressure declines more than 10 percent in a 30-minute test or if there
is another indication of a leak, you must re-cement, repair the casing,
or run additional casing to provide a proper seal. The District
Supervisor may approve or require other casing test pressures.
------------------------------------------------------------------------
Casing type Minimum test pressure
------------------------------------------------------------------------
(a) Drive or Structural............ Not required
(b) Conductor...................... 200 psi
(c) Surface, Intermediate, and 70 percent of its minimum internal
Production. yield
------------------------------------------------------------------------
Sec. 250.424 What are the requirements for prolonged drilling
operations?
If wellbore operations continue for more than 30 days within a
casing string run to the surface:
(a) You must stop drilling operations as soon as practicable, and
evaluate the effects of the prolonged operations on continued drilling
operations and the life of the well. At a minimum, you must:
(1) Caliper or pressure test the casing; and
(2) Report the results of your evaluation to the District
Supervisor and obtain approval of those results before resuming
operations.
(b) If casing integrity has deteriorated to a level below minimum
safety factors, you must:
(1) Repair the casing or run another casing string; and
(2) Obtain approval from the District Supervisor before you begin
repairs.
Sec. 250.425 What are the requirements for pressure testing liners?
(a) You must test each drilling liner (and liner-lap) to a pressure
at least equal to the anticipated pressure to which the liner will be
subjected during the formation pressure-integrity test below that liner
shoe, or subsequent liner shoes if set. The District Supervisor may
approve or require other liner test pressures.
(b) You must test each production liner (and liner-lap) to a
minimum of 500 psi above the formation fracture pressure at the casing
shoe into which the liner is lapped.
(c) You may not resume drilling or other down-hole operations until
you obtain a satisfactory pressure test. If the pressure declines more
than 10 percent in a 30-minute test or if there is another indication
of a leak, you must re-cement, repair the liner, or run additional
casing/liner to provide a proper seal.
[[Page 8428]]
Sec. 250.426 What are the recordkeeping requirements for casing and
liner pressure tests?
You must record the time, date, and results of each pressure test
in the driller's report maintained under standard industry practice. In
addition, you must record each test on a pressure chart and have your
onsite representative sign and date the test as being correct.
Sec. 250.427 What are the requirements for pressure integrity tests?
You must conduct a pressure integrity test below the surface casing
or liner and all intermediate casings or liners. The District
Supervisor may require you to run a pressure-integrity test at the
conductor casing shoe if warranted by local geologic conditions or the
planned casing setting depth. You must conduct each pressure integrity
test after drilling at least 10 feet but no more than 50 feet of new
hole below the casing shoe. You must test to either the formation leak-
off pressure or to an equivalent drilling fluid weight if identified in
an approved APD.
(a) You must use the pressure integrity test and related hole-
behavior observations, such as pore-pressure test results, gas-cut
drilling fluid, and well kicks to adjust the drilling fluid program and
the setting depth of the next casing string. You must record all test
results and hole-behavior observations made during the course of
drilling related to formation integrity and pore pressure in the
driller's report.
(b) While drilling, you must maintain the safe drilling margin
identified in the approved APD. When you cannot maintain this safe
margin, you must suspend drilling operations and remedy the situation.
Sec. 250.428 What must I do in certain cementing and casing
situations?
The table in this section describes actions that lessees must take
when certain situations occur during casing and cementing activities.
------------------------------------------------------------------------
If you encounter the following
situation: Then you must . . .
------------------------------------------------------------------------
(a) Have unexpected formation Submit a revised casing program to the
pressures or conditions that District Supervisor for approval.
warrant revising your casing
design.
(b) Need to increase casing Submit those changes to the District
setting depths more than 100 Supervisor for approval.
feet true vertical depth (TVD)
from the approved APD due to
conditions encountered during
drilling operations.
(c) Have indication of (1) Pressure test the casing shoe; (2)
inadequate cement job (such as Run a temperature survey; (3) Run a
lost returns, cement cement bond log; or (4) Use a
channeling, or failure of combination of these techniques.
equipment).
(d) Inadequate cement job....... Re-cement or take other remedial
actions as approved by the District
Supervisor.
(e) Primary cement job that did Isolate those intervals from normal
not isolate abnormal pressure pressures by squeeze cementing before
intervals. you complete; suspend operations; or
abandon the well, whichever occurs
first.
(f) Decide to produce a well Have at least two cemented casing
that was not originally strings (does not include liners) in
contemplated for production. the well. Note: All producing wells
must have at least two cemented
casing strings.
(g) Want to drill a well without Submit geologic data and information
setting conductor casing. to the District Supervisor that
demonstrates the absence of shallow
hydrocarbons or hazards. This
information must include logging and
drilling fluid-monitoring from wells
previously drilled within 500 feet of
the proposed well path down to the
next casing point.
(h) Need to use less than Submit information to the District
required cement for the surface Supervisor that demonstrates the use
casing during floating drilling of less cement is necessary.
operations to provide
protection from burst and
collapse pressures.
(i) Cement across a permafrost Use cement that sets before it freezes
zone. and has a low heat of hydration.
(j) Leave the annulus opposite a Fill the annulus with a liquid that
permafrost zone uncemented. has a freezing point below the
minimum permafrost temperature and
minimizes opposite a corrosion.
------------------------------------------------------------------------
Diverter System Requirements
Sec. 250.430 When must I install a diverter system?
You must install a diverter system before you drill a conductor or
surface hole. The diverter system consists of a diverter sealing
element, diverter lines, and control systems. You must design, install,
use, maintain, and test the diverter system to ensure proper diversion
of gases, water, drilling fluid, and other materials away from
facilities and personnel.
Sec. 250.431 What are the diverter design and installation
requirements?
You must design and install your diverter system to:
(a) Use diverter spool outlets and diverter lines that have a
nominal diameter of at least 10 inches for surface wellhead
configurations and at least 12 inches for floating drilling operations;
(b) Use dual diverter lines arranged to provide for downwind
diversion capability;
(c) Use at least two diverter control stations. One station must be
on the drilling floor. The other station must be in a readily
accessible location away from the drilling floor;
(d) Use only remote-controlled valves in the diverter lines. All
valves in the diverter system must be full-opening. You may not install
manual or butterfly valves in any part of the diverter system;
(e) Minimize the number of turns (only one 90-degree turn allowed
for each line for bottom-founded drilling units) in the diverter lines,
maximize the radius of curvature of turns, and target all right angles
and sharp turns;
(f) Anchor and support the entire diverter system to prevent
whipping and vibration; and
(g) Protect all diverter-control instruments and lines from
possible damage by thrown or falling objects.
Sec. 250.432 How do I obtain a departure to diverter design and
installation requirements?
The table below describes possible departures from the diverter
requirements and the conditions required for each departure. To obtain
one of these departures, you must have discussed the departure in your
APD and received approval from the District Supervisor.
[[Page 8429]]
------------------------------------------------------------------------
If you want a departure to: Then you must...
------------------------------------------------------------------------
(a) Use flexible hose for Use flexible hose that has integral
diverter lines instead of rigid end couplings.
pipe.
(b) Use only one spool outlet (1) Have branch lines that meet the
for your diverter system. minimum internal diameter
requirements; and (2) Provide
downwind diversion capability.
(c) Use a spool with an outlet Use a spool that has dual outlets with
with an internal diameter of an internal diameter of at least 8
less than 10 inches on a inches.
surface wellhead.
(d) Use a single diverter line Maintain an appropriate vessel heading
for floating drilling to provide for downwind diversion.
operations on a dynamically
positioned drillship.
------------------------------------------------------------------------
Sec. 250.433 What are the diverter actuation and testing
requirements?
When you install the diverter system, you must actuate the diverter
sealing element, diverter valves, and diverter-control systems and
control stations. You must also flow-test the vent lines.
(a) For drilling operations with a surface wellhead configuration,
you must actuate the diverter system at least once every 24-hour period
after the initial test. After you have nippled up on conductor casing,
you must pressure-test the diverter-sealing element and diverter valves
to a minimum of 200 psi. While the diverter is installed, you must
conduct subsequent pressure tests within 7 days after the previous
test.
(b) For floating drilling operations with a subsea BOP stack, you
must actuate the diverter system within 7 days after the previous
actuation.
(c) You must alternate actuations and tests between control
stations.
Sec. 250.434 What are the recordkeeping requirements for diverter
actuations and tests?
You must record the time, date, and results of all diverter
actuations and tests in the driller's report. In addition, you must:
(a) Record the diverter pressure test on a pressure chart;
(b) Require your onsite representative to sign and date the
pressure test chart;
(c) Identify the control station used during the test or actuation;
(d) Identify problems or irregularities observed during the testing
or actuations and record actions taken to remedy the problems or
irregularities; and
(e) Retain all pressure charts and reports pertaining to the
diverter tests and actuations at the facility for the duration of
drilling the well.
Blowout Preventer (BOP) System Requirements
Sec. 250.440 What are the general requirements for BOP systems and
system components?
You must design, install, maintain, test, and use the BOP system
and system components to ensure well control. The working-pressure
rating of each BOP component must exceed maximum anticipated surface
pressures. The BOP system includes the BOP stack and associated BOP
systems and equipment.
Sec. 250.441 What are the requirements for a surface BOP stack?
(a) When you drill with a surface BOP stack, you must install the
BOP system before drilling below surface casing. The surface BOP stack
must include at least four remote-controlled, hydraulically operated
BOPs, consisting of an annular BOP, two BOPs equipped with pipe rams,
and one BOP equipped with blind or blind-shear rams.
(b) No later than February 21, 2006, your surface BOP stack must
include at least four remote-controlled, hydraulically operated BOPs
consisting of an annular BOP, two BOPs equipped with pipe rams, and one
BOP equipped with blind-shear rams. The blind-shear rams must be
capable of shearing the drill pipe that is in the hole.
(c) You must install an accumulator system that provides 1.5 times
the volume of fluid capacity necessary to close and hold closed all BOP
components. The system must perform with a minimum pressure of 200 psi
above the precharge pressure without assistance from a charging system.
If you supply the accumulator regulators by rig air and do not have a
secondary source of pneumatic supply, you must equip the regulators
with manual overrides or other devices to ensure capability of
hydraulic operations if rig air is lost.
(d) In addition to the stack and accumulator system, you must
install the associated BOP systems and equipment required by the
regulations in this subpart.
Sec. 250.442 What are the requirements for a subsea BOP stack?
(a) When you drill with a subsea BOP stack, you must install the
BOP system before drilling below surface casing. The District
Supervisor may require you to install a subsea BOP system before
drilling below the conductor casing if proposed casing setting depths
or local geology indicate the need.
(b) Your subsea BOP stack must include at least four remote-
controlled, hydraulically operated BOPs consisting of an annular BOP,
two BOPs equipped with pipe rams, and one BOP equipped with blind-shear
rams.
(c) You must install an accumulator closing system to provide fast
closure of the BOP components and to operate all critical functions in
case of a loss of the power fluid connection to the surface. The
accumulator system must meet or exceed the provisions of Section 13.3,
Accumulator Volumetric Capacity, in API RP 53, Recommended Practices
for Blowout Prevention Equipment Systems for Drilling Wells
(incorporated by reference as specified in Sec. 250.198). The District
Supervisor may approve a suitable alternative method.
(d) The BOP system must include an operable dual-pod control system
to ensure proper and independent operation of the BOP system.
(e) Before removing the marine riser, you must displace the riser
with seawater. You must maintain sufficient hydrostatic pressure or
take other suitable precautions to compensate for the reduction in
pressure and to maintain a safe and controlled well condition.
Sec. 250.443 What associated systems and related equipment must all
BOP systems include?
All BOP systems must include the following associated systems and
related equipment:
(a) An automatic backup to the primary accumulator-charging system.
The power source must be independent from the power source for the
primary accumulator-charging system. The independent power source must
possess sufficient capability to close and hold closed all BOP
components.
(b) At least two BOP control stations. One station must be on the
drilling floor. You must locate the other station in a readily
accessible location away from the drilling floor.
(c) Side outlets on the BOP stack for separate kill and choke
lines. If your stack does not have side outlets, you must install a
drilling spool with side outlets.
[[Page 8430]]
(d) A choke and a kill line on the BOP stack. You must equip each
line with two full-opening valves, one of which must be remote-
controlled. For a subsea BOP system, both valves in each line must be
remote-controlled. In addition:
(1) You must install the choke line above the bottom ram;
(2) You may install the kill line below the bottom ram; and
(3) For a surface BOP system, on the kill line you may install a
check valve and a manual valve instead of the remote-controlled valve.
To use this configuration, both manual valves must be readily
accessible and you must install the check valve between the manual
valves and the pump.
(e) A fill-up line above the uppermost BOP.
(f) Locking devices installed on the ram-type BOPs.
(g) A wellhead assembly with a rated working pressure that exceeds
the maximum anticipated surface pressure.
Sec. 250.444 What are the choke manifold requirements?
(a) Your BOP system must include a choke manifold that is suitable
for the anticipated surface pressures, anticipated methods of well
control, the surrounding environment, and the corrosiveness, volume,
and abrasiveness of drilling fluids and well fluids that you may
encounter.
(b) Choke manifold components must have a rated working pressure at
least as great as the rated working pressure of the ram BOPs. If your
choke manifold has buffer tanks downstream of choke assemblies, you
must install isolation valves on any bleed lines.
(c) Valves, pipes, flexible steel hoses, and other fittings
upstream of the choke manifold must have a rated working pressure at
least as great as the rated working pressure of the ram BOPs.
Sec. 250.445 What are the requirements for kelly valves, inside BOPs,
and drill-string safety valves?
You must use or provide the following BOP equipment during drilling
operations:
(a) A kelly valve installed below the swivel (upper kelly valve);
(b) A kelly valve installed at the bottom of the kelly (lower kelly
valve). You must be able to strip the lower kelly valve through the BOP
stack;
(c) If you drill with a mud motor and use drill pipe instead of a
kelly, you must install one kelly valve above, and one strippable kelly
valve below, the joint of drill pipe used in place of a kelly;
(d) On a top-drive system equipped with a remote-controlled valve,
you must install a strippable kelly-type valve below the remote-
controlled valve;
(e) An inside BOP in the open position located on the rig floor.
You must be able to install an inside BOP for each size connection in
the drill string;
(f) A drill-string safety valve in the open position located on the
rig floor. You must have a drill-string safety valve available for each
size connection in the drill string;
(g) When running casing, you must have a safety valve in the open
position available on the rig floor to fit the casing string being run
in the hole;
(h) All required manual and remote-controlled kelly valves, drill-
string safety valves, and comparable-type valves (i.e. kelly-type valve
in a top-drive system) must be essentially full-opening; and
(i) The drilling crew must have ready access to a wrench to fit
each manual valve.
Sec. 250.446 What are the BOP maintenance and inspection
requirements?
(a) You must maintain your BOP system to ensure that the equipment
functions properly. BOP maintenance must meet or exceed the provisions
of Sections 17.10 and 18.10, Inspections; Sections 17.11 and 18.11,
Maintenance; and Sections 17.12 and 18.12, Quality Management,
described in API RP 53, Recommended Practices for Blowout Prevention
Equipment Systems for Drilling Wells (incorporated by reference as
specified in Sec. 250.198).
(b) You must visually inspect your surface BOP system on a daily
basis. You must visually inspect your subsea BOP system and marine
riser at least once every 3 days if weather and sea conditions permit.
You may use television cameras to inspect subsea equipment.
Sec. 250.447 When must I pressure test the BOP system?
You must pressure test your BOP system (this includes the choke
manifold, kelly valves, inside BOP, and drill-string safety valve):
(a) When installed;
(b) Before 14 days have elapsed since your last BOP pressure test.
You must begin to test your BOP system before midnight on the 14th day
following the conclusion of the previous test. However, the District
Supervisor may require more frequent testing if conditions or BOP
performance warrant; and
(c) Before drilling out each string of casing or a liner. The
District Supervisor may allow you to omit this test if you didn't
remove the BOP stack to run the casing string or liner and the required
BOP test pressures for the next section of the hole are not greater
than the test pressures for the previous BOP test. You must indicate in
your APD which casing strings and liners meet these criteria.
Sec. 250.448 What are the BOP pressure tests requirements?
When you pressure test the BOP system, you must conduct a low-
pressure and a high-pressure test for each BOP component. You must
conduct the low-pressure test before the high-pressure test. Each
individual pressure test must hold pressure long enough to demonstrate
that the tested component(s) holds the required pressure. Required test
pressures are as follows:
(a) Low-pressure test. All low-pressure tests must be between 200
and 300 psi. Any initial pressure above 300 psi must be bled back to a
pressure between 200 and 300 psi before starting the test. If the
initial pressure exceeds 500 psi, you must bleed back to zero and
reinitiate the test.
(b) High-pressure test for ram-type BOPs, the choke manifold, and
other BOP components. The high-pressure test must equal the rated
working pressure of the equipment or be 500 psi greater than your
calculated maximum anticipated surface pressure (MASP) for the
applicable section of hole. Before you may test BOP equipment to the
MASP plus 500 psi, the District Supervisor must have approved those
test pressures in your APD.
(c) High pressure test for annular-type BOPs. The high pressure
test must equal 70 percent of the rated working pressure of the
equipment or to a pressure approved in your APD.
(d) Duration of pressure test. Each test must hold the required
pressure for 5 minutes. However, for surface BOP systems and surface
equipment of a subsea BOP system, a 3-minute test duration is
acceptable if you record your test pressures on the outermost half of a
4-hour chart, on a 1-hour chart, or on a digital recorder. If the
equipment does not hold the required pressure during a test, you must
correct the problem and retest the affected component(s).
Sec. 250.449 What additional BOP testing requirements must I meet?
You must meet the following additional BOP testing requirements:
(a) Use water to test a surface BOP system;
(b) Stump test a subsea BOP system before installation. You must
use water to conduct this test. You may use drilling fluids to conduct
subsequent tests of a subsea BOP system;
[[Page 8431]]
(c) Alternate tests between control stations and pods;
(d) Pressure test the blind or blind-shear ram BOP during stump
tests and at all casing points;
(e) The interval between any blind or blind-shear ram BOP pressure
tests may not exceed 30 days;
(f) Pressure test variable bore-pipe ram BOPs against the largest
and smallest sizes of pipe in use, excluding drill collars and bottom-
hole tools;
(g) Pressure test affected BOP components following the
disconnection or repair of any well-pressure containment seal in the
wellhead or BOP stack assembly;
(h) Function test annular and ram BOPs every 7 days between
pressure tests; and
(i) Actuate safety valves assembled with proper casing connections
before running casing.
Sec. 250.450 What are the recordkeeping requirements for BOP tests?
You must record the time, date, and results of all pressure tests,
actuations, and inspections of the BOP system, system components, and
marine riser in the driller's report. In addition, you must:
(a) Record BOP test pressures on pressure charts;
(b) Require your onsite representative to sign and date BOP test
charts and reports as correct;
(c) Document the sequential order of BOP and auxiliary equipment
testing and the pressure and duration of each test. For subsea BOP
systems, you must also record the closing times for annular and ram
BOPs. You may reference a BOP test plan if it is available at the
facility;
(d) Identify the control station and pod used during the test;
(e) Identify any problems or irregularities observed during BOP
system testing and record actions taken to remedy the problems or
irregularities; and
(f) Retain all records, including pressure charts, driller's
report, and referenced documents pertaining to BOP tests, actuations,
and inspections at the facility for the duration of drilling.
Sec. 250.451 What must I do in certain situations involving BOP
equipment or systems?
The table in this section describes actions that lessees must take
when certain situations occur with BOP systems during drilling
activities.
------------------------------------------------------------------------
If you encounter the following
situation: Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the Correct the problem and retest the
required pressure during a test. affected equipment.
(b) Need to repair or replace a First place the well in a safe,
surface or subsea BOP system. controlled condition (e.g., before
drilling out a casing shoe or
after setting a cement plug,
bridge plug, or a packer).
(c) Need to postpone a BOP test due Record the reason for postponing
to well-control problems such as the test in the driller's report
lost circulation, formation fluid and conduct the required BOP test
influx, or stuck drill pipe. on the first trip out of the hole.
(d) BOP control station or pod that Suspend further drilling operations
does not function properly. until that station or pod is
operable.
(e) Want to drill with a tapered Install two or more sets of
drill-string. conventional or variable-bore pipe
rams in the BOP stack to provide
for the following: two sets of
rams must be capable of sealing
around the larger-size drill
string and one set of pipe rams
must be capable of sealing around
the smaller-size drill string.
(f) Install casing rams in a BOP Test the ram bonnets before running
stack. casing.
(g) Want to use an annular BOP with Demonstrate that your well control
a rated working pressure less than procedures or the anticipated well
the anticipated surface pressure. conditions will not place demands
above its rated working pressure
and obtain approval from the
District Supervisor.
(h) Use a subsea BOP system in an Install the BOP stack in a glory
ice-scour area. hole. The glory hole must be deep
enough to ensure that the top of
the stack is below the deepest
probable ice-scour depth.
------------------------------------------------------------------------
Drilling Fluid Requirements
Sec. 250.455 What are the general requirements for a drilling fluid
program?
You must design and implement your drilling fluid program to
prevent the loss of well control. This program must address drilling
fluid safe practices, testing and monitoring equipment, drilling fluid
quantities, and drilling fluid-handling areas.
Sec. 250.456 What safe practices must the drilling fluid program
follow?
Your drilling fluid program must include the following safe
practices:
(a) Before starting out of the hole with drill pipe, you must
properly condition the drilling fluid. You must circulate a volume of
drilling fluid equal to the annular volume with the drill pipe just
off-bottom. You may omit this practice if documentation in the
driller's report shows:
(1) No indication of formation fluid influx before starting to pull
the drill pipe from the hole;
(2) The weight of returning drilling fluid is within 0.2 pounds per
gallon (1.5 pounds per cubic foot) of the drilling fluid entering the
hole; and
(3) Other drilling fluid properties are within the limits
established by the program approved in the APD.
(b) Record each time you circulate drilling fluid in the hole in
the driller's report;
(c) When coming out of the hole with drill pipe, you must fill the
annulus with drilling fluid before the hydrostatic pressure decreases
by 75 psi, or every five stands of drill pipe, whichever gives a lower
decrease in hydrostatic pressure. You must calculate the number of
stands of drill pipe and drill collars that you may pull before you
must fill the hole. You must also calculate the equivalent drilling
fluid volume needed to fill the hole. Both sets of numbers must be
posted near the driller's station. You must use a mechanical,
volumetric, or electronic device to measure the drilling fluid required
to fill the hole;
(d) You must run and pull drill pipe and downhole tools at
controlled rates so you do not swab or surge the well;
(e) When there is an indication of swabbing or influx of formation
fluids, you must take appropriate measures to control the well. You
must circulate and condition the well, on or near-bottom, unless well
or drilling-fluid conditions prevent running the drill pipe back to the
bottom;
(f) You must calculate and post near the driller's console the
maximum pressures that you may safely contain under a shut-in BOP for
each casing string. The pressures posted must consider the surface
pressure at which the formation at the shoe would break
[[Page 8432]]
down, the rated working pressure of the BOP stack, and 70 percent of
casing burst (or casing test as approved by the District Supervisor).
As a minimum, you must post the following two pressures:
(1) The surface pressure at which the shoe would break down. This
calculation must consider the current drilling fluid weight in the
hole; and
(2) The lesser of the BOP's rated working pressure or 70 percent of
casing-burst pressure (or casing test otherwise approved by the
District Supervisor);
(g) You must install an operable drilling fluid-gas separator and
degasser before you begin drilling operations. You must maintain this
equipment throughout the drilling of the well;
(h) Before pulling drill-stem test tools from the hole, you must
circulate or reverse-circulate the test fluids in the hole. If
circulating out test fluids is not feasible, you may bullhead test
fluids out of the drill-stem test string and tools with an appropriate
kill weight fluid;
(i) When circulating, you must test the drilling fluid at least
once each hour, or more frequently if conditions warrant. Your tests
must conform to industry-accepted practices and include density,
viscosity, and gel strength; hydrogenion concentration; filtration; and
any other tests the District Supervisor requires for monitoring and
maintaining drilling fluid quality, prevention of downhole equipment
problems and for kick detection. You must record the results of these
tests in the drilling fluid report; and
(j) In areas where permafrost and/or hydrate zones are present or
may be present, you must control drilling fluid temperatures to drill
safely through those zones.
Sec. 250.457 What equipment is required to monitor drilling fluids?
Once you establish drilling fluid returns, you must install and
maintain the following drilling fluid-system monitoring equipment
throughout subsequent drilling operations. This equipment must have the
following indicators on the rig floor:
(a) Pit level indicator to determine drilling fluid-pit volume
gains and losses. This indicator must include both a visual and an
audible warning device;
(b) Volume measuring device to accurately determine drilling fluid
volumes required to fill the hole on trips;
(c) Return indicator devices that indicate the relationship between
drilling fluid-return flow rate and pump discharge rate. This indicator
must include both a visual and an audible warning device; and
(d) Gas-detecting equipment to monitor the drilling fluid returns.
The indicator may be located in the drilling fluid-logging compartment
or on the rig floor. If the indicators are only in the logging
compartment, you must continually man the equipment and have a means of
immediate communication with the rig floor. If the indicators are on
the rig floor only, you must install an audible alarm.
Sec. 250.458 What quantities of drilling fluids are required?
(a) You must use, maintain, and replenish quantities of drilling
fluid and drilling fluid materials at the drill site as necessary to
ensure well control. You must determine those quantities based on known
or anticipated drilling conditions, rig storage capacity, weather
conditions, and estimated time for delivery.
(b) You must record the daily inventories of drilling fluid and
drilling fluid materials, including weight materials and additives in
the drilling fluid report.
(c) If you do not have sufficient quantities of drilling fluid and
drilling fluid material to maintain well control, you must suspend
drilling operations.
Sec. 250.459 What are the safety requirements for drilling fluid-
handling areas?
You must classify drilling fluid-handling areas according to API RP
500, Recommended Practice for Classification of Locations for
Electrical Installations at Petroleum Facilities, Classified as Class
I, Division 1 and Division 2 (incorporated by reference as specified in
Sec. 250.198); or API RP 505, Recommended Practice for Classification
of Locations for Electrical Installations at Petroleum Facilities,
Classified as Class 1, Zone 0, Zone 1, and Zone 2 (incorporated by
reference as specified in Sec. 250.198). In areas where dangerous
concentrations of combustible gas may accumulate, you must install and
maintain a ventilation system and gas monitors. Drilling fluid-handling
areas must have the following safety equipment:
(a) A ventilation system capable of replacing the air once every 5
minutes or 1.0 cubic feet of air-volume flow per minute, per square
foot of area, whichever is greater. In addition:
(1) If natural means provide adequate ventilation, then a
mechanical ventilation system is not necessary;
(2) If a mechanical system does not run continuously, then it must
activate when gas detectors indicate the presence of 1 percent or more
of combustible gas by volume; and
(3) If discharges from a mechanical ventilation system may be
hazardous, then you must maintain the drilling fluid-handling area at a
negative pressure. You must protect the negative pressure area by using
at least one of the following: a pressure-sensitive alarm, open-door
alarms on each access to the area, automatic door-closing devices, air
locks, or other devices approved by the District Supervisor;
(b) Gas detectors and alarms except in open areas where adequate
ventilation is provided by natural means. You must test and recalibrate
gas detectors quarterly. No more than 90 days may elapse between tests;
(c) Explosion-proof or pressurized electrical equipment to prevent
the ignition of explosive gases. Where you use air for pressuring
equipment, you must locate the air intake outside of and as far as
practicable from hazardous areas; and
(d) Alarms that activate when the mechanical ventilation system
fails.
Other Drilling Requirements
Sec. 250.460 What are the requirements for conducting a well test?
(a) If you intend to conduct a well test, you must include your
projected plans for the test with your APD (form MMS-123) or in an
Application for Permit to Modify (APM) (form MMS-124). Your plans must
include at least the following information:
(1) Estimated flowing and shut-in tubing pressures;
(2) Estimated flow rates and cumulative volumes;
(3) Time duration of flow, buildup, and drawdown periods;
(4) Description and rating of surface and subsurface test
equipment;
(5) Schematic drawing, showing the layout of test equipment;
(6) Description of safety equipment, including gas detectors and
fire-fighting equipment;
(7) Proposed methods to handle or transport produced fluids; and
(8) Description of the test procedures.
(b) You must give the District Supervisor at least 24-hours notice
before starting a well test.
Sec. 250.461 What are the requirements for directional and
inclination surveys?
For this subpart, MMS classifies a well as vertical if the
calculated average of inclination readings does not exceed 3 degrees
from the vertical.
(a) Survey requirements for a vertical well. (1) You must conduct
inclination surveys on each vertical well and record the results.
Survey intervals may not exceed 1,000 feet during the normal course of
drilling;
[[Page 8433]]
(2) You must also conduct a directional survey that provides both
inclination and azimuth, and digitally record the results in electronic
format:
(i) Within 500 feet of setting surface or intermediate casing;
(ii) Within 500 feet of setting any liner; and
(iii) When you reach total depth.
(b) Survey requirements for directional well. You must conduct
directional surveys on each directional well and digitally record the
results. Surveys must give both inclination and azimuth at intervals
not to exceed 500 feet during the normal course of drilling. Intervals
during angle-changing portions of the hole may not exceed 100 feet.
(c) Measurement while drilling. You may use measurement-while-
drilling technology if it meets the requirements of this section.
(d) Composite survey requirements.
(1) Your composite directional survey must show the interval from
the bottom of the conductor casing to total depth. In the absence of
conductor casing, the survey must show the interval from the bottom of
the drive or structural casing to total depth; and
(2) You must correct all surveys to Universal-Transverse-Mercator-
Grid-north or Lambert-Grid-north after making the magnetic-to-true-
north correction. Surveys must show the magnetic and grid corrections
used and include a listing of the directionally computed inclinations
and azimuths.
(e) If you drill within 500 feet of an adjacent lease, the Regional
Supervisor may require you to furnish a copy of the well's directional
survey to the affected leaseholder. This could occur when the adjoining
leaseholder requests a copy of the survey for the protection of
correlative rights.
Sec. 250.462 What are the requirements for well-control drills?
You must conduct a weekly well-control drill with each drilling
crew. Your drill must familiarize the crew with its roles and functions
so that all crew members can perform their duties promptly and
efficiently.
(a) Well-control drill plan. You must prepare a well control drill
plan for each well. Your plan must outline the assignments for each
crew member and establish times to complete each portion of the drill.
You must post a copy of the well control drill plan on the rig floor or
bulletin board.
(b) Timing of drills. You must conduct each drill during a period
of activity that minimizes the risk to drilling operations. The timing
of your drills must cover a range of different operations, including
drilling with a diverter, on-bottom drilling, and tripping.
(c) Recordkeeping requirements. For each drill, you must record the
following in the driller's report:
(1) The time to be ready to close the diverter or BOP system; and
(2) The total time to complete the entire drill.
(d) MMS ordered drill. An MMS authorized representative may require
you to conduct a well control drill during an MMS inspection. The MMS
representative will consult with your onsite representative before
requiring the drill.
Sec. 250.463 Who establishes field drilling rules?
(a) The District Supervisor may establish field drilling rules
different from the requirements of this subpart when geological and
engineering information shows that specific operating requirements are
appropriate. You must comply with field drilling rules and
nonconflicting requirements of this subpart. The District Supervisor
may amend or cancel field drilling rules at any time.
(b) You may request the District Supervisor to establish, amend, or
cancel field drilling rules.
Applying for a Permit to Modify and Well Records
Sec. 250.465 When must I submit an Application for Permit to Modify
(APM) or an End of Operations Report to MMS?
(a) You must submit an APM (form MMS-124) or an End of Operations
Report (form MMS-125) and other materials to the Regional Supervisor as
shown in the following table. You must also submit a public information
copy of each form.
----------------------------------------------------------------------------------------------------------------
When you Then you must And
----------------------------------------------------------------------------------------------------------------
(1)Intend to revise your drilling Submit form MMS-124 or Receive written or oral approval from the
plan, change major drilling request oral approval. District Supervisor before you begin the
equipment, or plugback. intended operation. If you get an approval,
you must submit form MMS-124 no later than
the end of the 3rd business day following the
oral approval. In all cases, or you must meet
the additional requirements in paragraph (b)
of this section.
(2) Determine a well's final Immediately Submit a form Submit a plat certified by a registered land
surface location, water depth, and MMS-124. surveyor that meets the requirements of Sec.
the rotary kelly bushing elevation. 250.412.
(3) Move a drilling unit from a Submit forms Submit MMS-124 Submit appropriate copies of the well recods.
wellbore before completing a well. and MMS-125 within 30 days
after the susepsion of
wellbore operations.
----------------------------------------------------------------------------------------------------------------
(b) If you intend to perform any of the actions specified in
paragraph (a)(1) of this section, you must meet the following
additional requirements:
(1) Your form MMS-124 must contain a detailed statement of the
proposed work that will materially change from the approved APD;
(2) Your form MMS-124 must include the present status of the well,
depth of all casing strings set to date, well depth, present production
zones and productive capability, and all other information specified;
and
(3) Within 30 days after completing this work, you must submit form
MMS-124 with detailed information about the work to the District
Supervisor, unless you have already provided sufficient information in
a Well Activity Report, form MMS-133 (Sec. 250.468(b)).
Sec. 250.466 What records must I keep?
You must keep complete, legible, and accurate records for each
well. You must keep drilling records onsite while drilling activities
continue. After completion of drilling activities, you must keep all
drilling and other well records for the time periods shown in Sec.
250.469. You may keep these records at a location of your choice. The
records must contain complete information on all of the following:
(a) Well operations;
(b) Descriptions of formations penetrated;
[[Page 8434]]
(c) Content and character of oil, gas, water, and other mineral
deposits in each formation;
(d) Kind, weight, size, grade, and setting depth of casing;
(e) All well logs and surveys run in the wellbore;
(f) Any significant malfunction or problem; and
(g) All other information required by the District Supervisor in
the interests of resource evaluation, waste prevention, conservation of
natural resources, and the protection of correlative rights, safety,
and environment.
Sec. 250.467 How long must I keep records?
You must keep records for the time periods shown in the following
table.
------------------------------------------------------------------------
You must keep records relating to Until
------------------------------------------------------------------------
(a) Drilling........................... Ninety days after you complete
drilling operations.
(b) Casing and liner pressure tests, Two years after the completion
diverter tests, and BOP tests. of drilling operations.
(c) Completion of a well or of any You permanently plug and
workover activity that materially abandon the well or until you
alters the completion configuration or forward the records with a
affects a hydrocarbon-bearing zone. lease assignment.
------------------------------------------------------------------------
Sec. 250.468 What well records am I required to submit?
(a) You must submit copies of logs or charts of electrical,
radioactive, sonic, and other well-logging operations; directional and
vertical-well surveys; velocity profiles and surveys; and analysis of
cores to MMS. Each Region will provide specific instructions for
submitting well logs and surveys.
(b) For drilling operations in the GOM OCS Region, you must submit
form MMS-133, Well Activity Report, to the District Supervisor on a
weekly basis.
(c) For drilling operations in the Pacific or Alaska OCS Regions,
you must submit form MMS-133, Well Activity Report, to the District
Supervisor on a daily basis.
Sec. 250.469 What other well records could I be required to submit?
The Regional or District Supervisor may require you to submit
copies of any or all of the following well records.
(a) Well records as specified in Sec. 250.466;
(b) Paleontological interpretations or reports identifying
microscopic fossils by depth and/or washed samples of drill cuttings
that you normally maintain for paleontological determinations. The
Regional Supervisor may issue a Notice to Lessees that prescribes the
manner, timeframe, and format for submitting this information;
(c) Service company reports on cementing, perforating, acidizing,
testing, or other similar services; or
(d) Other reports and records of operations.
Hydrogren Sulfide
* * * * *
9. In the newly redesignated Sec. 250.490, paragraphs (g)(4)(iv),
(j)(13)(ii), and (p)(2) are revised to read as follows:
Sec. 250.490 Hydrogen sulfide.
* * * * *
(g) * * *
(4) * * *
(iv) Restrictions and corrective measures concerning beards,
spectacles, and contact lenses in conformance with ANSI Z88.2, American
National Standard for Respiratory Protection (incorporated by reference
as specified in Sec. 250.198);
* * * * *
(j) * * *
(13) * * *
(ii) Design, select, use, and maintain respirators in conformance
with ANSI Z88.2 (incorporated by reference as specified in Sec.
250.198).
* * * * *
(p) * * *
(2) Use BOP system components, wellhead, pressure-control
equipment, and related equipment exposed to H2S-bearing
fluids in conformance with NACE Standard MR0175-99 (incorporated by
reference as specified in Sec. 250.198).
* * * * *
Sec. 250.504 [Amended]
10. In Sec. 250.504, in the first and last sentences, the citation
``Sec. 250.417'' is revised to read ``Sec. 250.490''.
Sec. 250.513 [Amended]
11. In Sec. 250.513, the following changes are made:
A. In paragraph (a), the citation ``Sec. 250.414'' is revised to
read ``Sec. 250.410 through Sec. 250.418''.
B. In paragraph (b)(4), the citation ``Sec. 250.417'' is revised
to read ``Sec. 250.490''.
12. In Sec. 250.515, paragraph (b) is revised to read as follows:
Sec. 250.515 Blowout prevention equipment.
* * * * *
(b) The minimum BOP system for well-completion operations must meet
the appropriate standards from the following table:
----------------------------------------------------------------------------------------------------------------
When The minimum BOP stack must include
----------------------------------------------------------------------------------------------------------------
(1) The expected pressure is less than 5,000 Three BOPs consisting of an annular, one set of pipe rams, and one
psi. set of blind or blind-shear rams.
(2) The expected pressure is 5,000 psi or Four BOPs consisting of an annular, two sets of pipe rams, and one
greater or you use multiple tubing strings. set of blind or blind-shear rams.
(3) You handle multiple tubing strings Four BOPs consisting of an annular, one set of pipe rams, one set
simultaneously. of dual pipe rams, and one set of blind or blind-shear rams.
(4) You use a tapered drill string.......... At least one set of pipe rams that are capable of sealing around
each size of drill string. If the expected pressure is greater
than 5,000 psi, then you must have at least two sets of pipe rams
that are capable of sealing around the larger size drill string.
You may substitute one set of variable bore rams for two sets of
pipe rams.
(5) It is after February 21, 2006........... At least one set of blind-shear rams. The blind-shear rams must be
capable of shearing the drill pipe or tubing in the hole.
----------------------------------------------------------------------------------------------------------------
[[Page 8435]]
* * * * *
Sec. 250.604 [Amended]
13. In Sec. 250.604, in the first and last sentences, the citation
``Sec. 250.417'' is revised to read ``Sec. 250.490''.
Sec. 250.613 [Amended]
14. In Sec. 250.613(b)(3), the citation ``Sec. 250.417'' is
revised to read ``Sec. 250.490''.
15. In Sec. 250.615, paragraph (b) is revised to read as follows:
Sec. 250.615 Blowout prevention equipment.
* * * * *
(b) The minimum BOP system for well-workover operations with the
tree removed must meet the appropriate standards from the following
table:
----------------------------------------------------------------------------------------------------------------
When The minimum BOP stack must include
----------------------------------------------------------------------------------------------------------------
(1) The expected pressure is less than 5,000 Three BOPs consisting of an annular, one set of pipe rams, and one
psi. set of blind or blind-shear rams.
(2) The expected pressure is 5,000 psi or Four BOPs consisting of an annular, two sets of pipe rams, and one
greater or you use multiple tubing strings. set of blind or blind-shear rams.
(3) You handle multiple tubing strings Four BOPs consisting of an annular, one set of pipe rams, one set
simultaneously. of dual pipe rams, and one set of blind or blind-shear rams.
(4) You use a tapered drill string.......... At least one set of pipe rams that are capable of sealing around
each size of drill string. If the expected pressure is greater
than 5,000 psi, then you must have at least two sets of pipe rams
that are capable of sealing around the larger size drill string.
You may substitute one set of variable bore rams for two sets of
pipe rams.
(5) It is after February 21, 2006........... At least one set of blind-shear rams. The blind-shear rams must be
capable of shearing the drill pipe or tubing in the hole.
----------------------------------------------------------------------------------------------------------------
Sec. 250.807 [Amended]
16. In Sec. 250.807, the citation ``Sec. 250.417'' is revised to
read ``Sec. 250.490''.
Sec. 250.1105 [Amended]
17a. In Sec. 250.1105(f)(1)(i), the citation ``Sec. 250.417(f)''
is revised to read ``Sec. 250.490(f)''.
Sec. 250.1604 [Amended]
17b. In Sec. 250.1604 in paragraph (b), in the first and third
sentences, the citation ``Sec. 250.417'' is revised to read ``Sec.
250.490''.
Sec. 250.1612 [Amended]
18. In Sec. 250.1612, the citation ``Sec. 250.408'' is revised to
read ``Sec. 250.462''.
Sec. 250.1614 [Amended]
19. In Sec. 250.1614, in paragraph (b), the citation ``Sec.
250.410(b), (c), (d), and (e)'' is revised to read ``Sec. 250.455
through Sec. 250.459''; and the citation ``Sec. 250.410(b)(8)'' is
revised to read ``Sec. 250.456(g)''.
[FR Doc. 03-3425 Filed 2-19-03; 8:45 am]
BILLING CODE 4310-MR-P